Edgar Filing: Ameren Illinois Co

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, 2010

		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	Ameren Illinois Company	37-0211380
	(Illinois Corporation)
	300 Liberty Street
	Peoria, Illinois 61602
	(309) 677-5271

333-56594	Ameren Energy Generating Company	37-1395586
	(Illinois Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222

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

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


Registrant		Title of each class

Ameren Corporation		Common Stock, $0.01 par value per share

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

Ameren Illinois Company		Preferred Stock, cumulative, $100 par value per share Depository Shares, each representing one-fourth of a share of 6.625% Preferred Stock, cumulative, $100 par value per share

Ameren Energy Generating Company does not have securities registered under either Section 12(b) or 12(g) of the Securities Exchange Act of 1934.

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

Ameren Corporation

Yes

)

(

)

Union Electric Company

Yes

)

(

)

Ameren Illinois Company

Yes

(

)

Ameren Energy Generating Company

Yes

(

)

Indicate by checkmark 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

(

)

Union Electric Company

Yes

(

)

Ameren Illinois Company

Yes

(

)

Ameren Energy Generating Company

Yes

(

)

Indicate by checkmark 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

)

(

)

Union Electric Company

Yes

)

(

)

Ameren Illinois Company

Yes

)

(

)

Ameren Energy Generating Company

Yes

)

(

)

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


Ameren Corporation		(X)
Union Electric Company		(X)
Ameren Illinois Company		(X)
Ameren Energy Generating Company		(X)

Indicate by checkmark whether each registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Ameren Corporation

Yes

)

(

)

Union Electric Company

Yes

(

)

(

)

Ameren Illinois Company

Yes

(

)

(

)

Ameren Energy Generating Company

Yes

(

)

(

)

Indicate by checkmark 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)	( )
Ameren Illinois Company	( )	( )	(X)	( )
Ameren Energy Generating Company	( )	( )	(X)	( )

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

Ameren Corporation

Yes

(

)

Union Electric Company

Yes

(

)

Ameren Illinois Company

Yes

(

)

Ameren Energy Generating Company

Yes

(

)

As of June 30, 2010, Ameren Corporation had 239,131,488 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 the common stock on the New York Stock Exchange on that date) held by nonaffiliates was $5,684,155,470. The shares of common stock of the other registrants were held by affiliates as of June 30, 2010.

The number of shares outstanding of each registrant’s classes of common stock as of January 31, 2011, was as follows:


Ameren Corporation		Common stock, $0.01 par value per share: 240,544,989

Union Electric Company		Common stock, $5 par value per share, held by Ameren Corporation (parent company of the registrant): 102,123,834

Ameren Illinois 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

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement of Ameren Corporation and portions of the definitive information statements of Union Electric Company and Ameren Illinois Company for the 2011 annual meetings of shareholders are incorporated by reference into Part III of this Form 10-K.

OMISSION OF CERTAIN INFORMATION

Ameren Energy Generating Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is 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, Ameren Illinois Company and Ameren Energy Generating 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		5
	General		5
	Business Segments		5
	Rates and Regulation		5
	Transmission and Supply of Electric Power		9
	Fuel for Power Generation		10
	Natural Gas Supply for Distribution		13
	Industry Issues		13
	Operating Statistics		14
	Available Information		16
Item 1A.	Risk Factors		16
Item 1B.	Unresolved Staff Comments		23
Item 2.	Properties		23
Item 3.	Legal Proceedings		25
Item 4.	[Removed and Reserved]		26

Executive Officers of the Registrants (Item 401(b) of Regulation S-K)			26

PART II
Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		28
Item 6.	Selected Financial Data.		31
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
	Overview		32
	Results of Operations		34
	Liquidity and Capital Resources		51
	Outlook		64
	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
	Selected Quarterly Information		171
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		172
Item 9A.	Controls and Procedures		172
Item 9B.	Other Information		173

PART III
Item 10.	Directors, Executive Officers and Corporate Governance		173
Item 11.	Executive Compensation		174
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		174
Item 13.	Certain Relationships and Related Transactions and Director Independence		175
Item 14.	Principal Accounting Fees and Services		175

PART IV
Item 15.	Exhibits and Financial Statement Schedules		175
SIGNATURES			178
EXHIBIT INDEX			182

This report 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 pages 3, 4 and 5 of this report 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.

2007 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 settlement, which became effective in 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 addressed the issue of power procurement, and it included a comprehensive rate relief and customer assistance program.

2009 Illinois Credit Agreement – Ameren’s and AIC’s $800 million senior secured credit agreement, which terminated on September 10, 2010.

2009 Multiyear Credit Agreement – Ameren’s, UE’s and Genco’s $1.15 billion credit agreement, which terminated on September 10, 2010. Collectively, this agreement and the 2009 Supplemental Credit Agreement are referred to herein as the “2009 Multiyear Credit Agreements.”

2009 Supplemental Credit Agreement – Ameren’s, UE’s and Genco’s $150 million supplemental credit agreement to the 2009 Multiyear Credit Agreement. This agreement expired in July 2010.

2010 Credit Agreements – The 2010 Genco Credit Agreement, the 2010 Illinois Credit Agreement, and the 2010 Missouri Credit Agreement, collectively.

2010 Genco Credit Agreement – On September 10, 2010, Ameren and Genco entered into a $500 million multiyear senior unsecured revolving credit facility. This agreement expires on September 10, 2013.

2010 Illinois Credit Agreement – On September 10, 2010, Ameren and AIC entered into an $800 million multiyear senior unsecured credit agreement. This agreement expires on September 10, 2013.

2010 Missouri Credit Agreement – On September 10, 2010, Ameren and UE entered into an $800 million multiyear senior unsecured revolving credit facility. This agreement expires on September 10, 2013, subject to UE’s borrowing sublimit extensions.

AERG – AmerenEnergy Resources Generating Company, a CILCO subsidiary until October 1, 2010, that operates a merchant electric generation business in Illinois. On October 1, 2010, AERG stock was distributed to Ameren and subsequently contributed by Ameren to Resources Company, which resulted in AERG becoming a subsidiary of Resources Company.

AFS – Ameren Energy Fuels and Services Company, a Resources Company subsidiary that procured fuel and natural gas and managed the related risks for the Ameren Companies prior to January 1, 2011. Effective January 1, 2011, the functions previously performed by AFS are performed within the Ameren Missouri, Ameren Illinois and Merchant Generation business segments.

AIC – Ameren Illinois Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. This

business consists of the combined rate-regulated electric and natural gas transmission and distribution businesses operated by CIPS, CILCO and IP before the AIC Merger. References to AIC prior to the AIC Merger refer collectively to the rate-regulated electric and natural gas transmission and distribution businesses of CIPS, CILCO and IP. Immediately after the AIC Merger, AIC distributed the common stock of AERG to Ameren Corporation. AERG is treated as a discontinued operation within AIC’s financial statements. AIC operates its business in Illinois as Ameren Illinois.

AIC Merger – On October 1, 2010, CILCO and IP merged with and into CIPS, with the surviving corporation renamed Ameren Illinois Company.

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 – A financial reporting segment consisting of AIC’s rate-regulated businesses. AIC also operates its business in Illinois as Ameren Illinois.

Ameren Missouri – A financial reporting segment consisting of UE’s rate-regulated businesses. UE also operates its business in Missouri as Ameren Missouri.

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

AMIL – The MISO balancing authority area operated by Ameren, which includes the load of AIC and the generating assets of Genco (excluding EEI and Genco’s Elgin CT facility) and AERG.

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

AMT – Alternative minimum tax.

ARO – Asset retirement obligations.

ATX – Ameren Transmission Company, an Ameren Corporation subsidiary dedicated to electric transmission infrastructure investment.

ATXI – Ameren Transmission Company of Illinois, an Ameren Corporation subsidiary that is engaged in the construction and operation of electric transmission assets in Illinois.

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.

CAIR – Clean Air Interstate Rule.

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

CATR – Clean Air Transport Rule.

CILCO – Central Illinois Light Company, a former Ameren Corporation subsidiary that operated a rate-regulated electric transmission and distribution business, a merchant electric generation business through AERG, and a rate-regulated natural gas transmission and distribution business, all in Illinois, before the AIC Merger. CILCO owned all of the common stock of AERG and included AERG within its consolidated financial statements. Immediately after the AIC Merger, AIC distributed the common stock of AERG to Ameren Corporation. AERG is treated as a discontinued operation within AIC’s financial statements.

CILCORP – CILCORP Inc., a former Ameren Corporation subsidiary that operated as a holding company for CILCO and its merchant generation subsidiary. On March 4, 2010, CILCORP merged with and into Ameren.

CIPS – Central Illinois Public Service Company, an Ameren Corporation subsidiary, renamed Ameren Illinois Company at the effective date of the AIC Merger, that operates a rate-regulated electric and natural gas transmission and distribution business, all in Illinois.

CO₂ – Carbon dioxide.

COLA – Combined nuclear plant 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 a 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 Genco subsidiary that operates merchant electric generation facilities and FERC-regulated transmission facilities in Illinois. Before 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. Effective January 1, 2010, in an internal reorganization, Resources Company contributed its 80% ownership interest in EEI to its subsidiary, Genco. The remaining 20% ownership interest is owned by Kentucky Utilities Company, a nonaffiliated entity.

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.

ESP – Early Site Permit.

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, greater or less than the amount set in base rates, without a traditional rate proceeding.

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.

Fitch – Fitch Ratings, a credit rating agency.

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 merchant electric generation business in Illinois and Missouri and holds an 80% ownership interest in EEI.

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 by 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 ATXI and AIC.

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

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

IP – Illinois Power Company, a former Ameren Corporation subsidiary that operated a rate-regulated electric and natural gas transmission and distribution business, all in Illinois, before the AIC Merger.

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.

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

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

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

LIUNA – Laborers’ International Union of North America, a labor union.

MACT – Maximum Achievable Control Technology.

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

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

Megawatthour – One thousand kilowatthours.

Merchant Generation – A financial reporting segment consisting primarily of the operations or activities of Resources Company, including Genco, Genco’s 80% ownership interest in EEI, AERG, Medina Valley and Marketing Company.

MGP – Manufactured gas plant.

MISO – Midwest Independent Transmission System Operator, Inc., an RTO.

MISO Energy and Operating Reserves Market – A market that uses market-based pricing, which takes into account transmission congestion and line losses, to compensate market participants for power and ancillary services.

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.

Mmbtu – One million Btus.

Money pool – Borrowing agreements among Ameren and its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools 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 UE.

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

MTM – Mark-to-market.

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.

NO_x – Nitrogen oxide.

Noranda – Noranda Aluminum, Inc.

NPNS – Normal purchases and normal sales.

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

NSPS – New Source Performance Standards, a provision under the Clean Air Act.

NSR – New Source Review provisions of the Clean Air Act, which include Nonattainment New Source Review and Prevention of Significant Deterioration regulations.

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 – The effect of adjustments to retail electric and natural gas rates being based on historic cost and revenue 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 and revenue when based on historical periods.

Resources Company – Ameren Energy Resources Company, LLC, an Ameren Corporation subsidiary that consists of non-rate-regulated operations, including Genco, Genco’s 80% ownership interest in EEI, AERG, Marketing Company and Medina Valley. On October 1, 2010, AERG stock was distributed to Ameren, which then contributed it to Resources Company, thereby making AERG a subsidiary of Resources Company.

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.

SO₂ – Sulfur dioxide.

UA – United Association of Plumbers and Pipefitters, a labor union.

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, doing business as Ameren Missouri.

VIE – Variable-interest entity.

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, judicial, or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the outcome of the pending UE electric rate proceeding and the AIC electric and natural gas rate proceeding; the court appeals and regulatory proceedings related to UE’s 2009 and 2010 electric rate orders and the court appeals related to AIC’s 2010 electric and natural gas rate order; and future regulatory, judicial, or legislative actions that seek to limit or reverse rate increases;

the effects of, or changes to, the Illinois power procurement process;

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

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;

the effects on demand for our services resulting from technological advances, including advances in energy efficiency and distributed generation sources, which generate electricity at the site of consumption;

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, or potential withdrawal from, 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;

the level and volatility of future prices for power in the Midwest;

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 and liquidity, impossible, more difficult, or more costly;

our assessment of our liquidity;

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

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

the impact of weather conditions and other natural phenomena on us and our customers;

the impact of system outages;

generation, transmission, and distribution asset construction, installation, performance, and cost recovery;

the extent to which UE prevails in its claims against insurers in connection with its Taum Sauk pumped-storage hydroelectric plant incident;

the extent to which UE is permitted by its regulators to recover in rates (i) certain of the Taum Sauk rebuild costs not covered by insurance and (ii) investments made in connection with a proposed second unit at its Callaway nuclear plant;

impairments of long-lived assets, intangible assets, or goodwill;

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

the effects of strategic initiatives, including mergers, 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, other emissions, and energy efficiency, will be enacted over time, which could limit or terminate the operation of certain of our generating units, increase our costs, result in an impairment of our assets, reduce our customers’ demand for electricity or natural gas, or otherwise have a negative financial effect;

the impact of complying with renewable energy portfolio requirements in Missouri;

labor disputes, work force reductions, 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 Inc. Ameren acquired CILCORP in 2003 and IP in 2004. Ameren’s primary assets are the common stock of its subsidiaries, including UE, AIC and Genco. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission, and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren depend on distributions made to it by its subsidiaries. Below is a summary description of UE, AIC and Genco. A more detailed description can be found in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.

UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.

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

Genco operates a merchant electric generation business in Illinois and Missouri.

As part of an internal reorganization, Resources Company transferred its 80% ownership interest in EEI to Genco, through a capital contribution, on January 1, 2010.

On October 1, 2010, after receiving all necessary approvals, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the AIC Merger. The second step of the reorganization involved the distribution of AERG stock from AIC to Ameren (the AERG distribution) and the subsequent contribution by Ameren of the AERG stock to Resources Company. For additional information regarding the corporate reorganization, see Note 16 – Corporate Reorganization and Discontinued Operations under Part II, Item 8, of this report.

The following table presents our total employees at December 31, 2010:


Ameren^(a)			9,474
UE			4,372
AIC			2,752
Genco			695

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

As of January 1, 2011, the IBEW, the IUOE, the LIUNA, the NCF&O and the UA labor unions collectively represented about 59% of Ameren’s total employees. They represented 64% of the employees at UE, 67% at AIC, and 67% at Genco. All collective bargaining agreements that expired in 2010 were renegotiated and ratified. The collective bargaining agreements have three- to five-year terms, and expire between 2011 and 2013. Several collective bargaining agreements between Ameren subsidiaries and the IBEW, IUOE, the LIUNA, NCF&O and the UA labor unions, covering approximately 925 employees, expire throughout 2011.

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 under Part II, Item 8, of this report.

BUSINESS SEGMENTS

Ameren has three reportable segments: Ameren Missouri, Ameren Illinois, and Merchant Generation. See Note 18 – Segment Information under Part II, Item 8, of this report for additional information on reporting segments.

RATES AND REGULATION

Rates

The rates that UE and AIC are allowed to charge for their utility services significantly influence the results of operations, financial position, and liquidity of these companies and Ameren. The electric and natural gas utility industry is highly regulated. The utility rates charged to UE and AIC customers are 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 prudency of expenditures, 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 are largely outside of UE’s and AIC’s control. These decisions, 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, and liquidity of Ameren, UE and AIC. Rate orders are also subject to appeal and stay requests, which create additional uncertainty as to the rates UE and AIC are ultimately allowed to charge for their services.

The ICC regulates rates and other matters for AIC and AITX. The MoPSC regulates rates and other matters for UE. The FERC regulates UE, AIC, Genco, and AITX 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 46% of Ameren’s electric and 15% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2010. About 31% of Ameren’s electric and 85% of its gas operating revenues were subject to regulation by the ICC in the year ended December 31, 2010. Wholesale revenues for UE, Genco and AERG are subject to FERC regulation, but not subject to direct MoPSC or ICC regulation.

Ameren Missouri (UE)

Electric

About 98% of UE’s electric operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2010. Beginning March 1, 2009, UE’s retail electric rates include a FAC that allows billing adjustments for changes in prudently incurred fuel and purchased power costs. On May 28, 2010, the MoPSC issued an order approving an increase for UE in annual revenues for electric service of approximately $230 million. This order allowed UE to continue to use the regulatory tracking mechanisms for vegetation management and infrastructure costs and pension and postretirement benefit costs. See below for cost recovery of energy efficiency programs. UE’s 2009 and 2010 electric rate orders are still subject to court appeals.

On September 3, 2010, UE filed a request with the MoPSC to increase its annual revenues for electric service by approximately $263 million. Approximately $110 million of the request relates to recovery of the cost of installing and operating two scrubbers at UE’s Sioux plant. Also included in this requested increase is a $73 million anticipated increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its May 2010 electric rate order. Absent initiation of this general rate proceeding, 95% of this amount would have been reflected in rate adjustments implemented under UE’s FAC. Capital additions relating to enhancements at the rebuilt Taum Sauk facility were also included in the increase request. As a part of its filing, UE also requested that the MoPSC approve the implementation of an infrastructure investment tracking mechanism as well as enhanced energy efficiency cost recovery. UE also requested continued use of its existing FAC, vegetation management and infrastructure cost tracker, and the regulatory tracking mechanism for pension and postretirement benefit costs the MoPSC previously authorized in earlier electric rate orders. In February 2011, the MoPSC staff responded to the UE request for an electric service rate increase. The MoPSC staff recommended an increase to UE’s annual revenues of between $45 million and $99 million based on a return on equity of 8.25% to

9.25%. Included in this recommendation was approximately $50 million of increases in normalized net fuel costs and $32 million of asset disallowances relating to the Sioux plant scrubbers. Other parties also made recommendations through testimony filed in this case.

FERC regulates the rates charged and the terms and conditions for electric transmission services. Each RTO separately files a regional transmission tariff for approval by FERC. All transmission service within that RTO is then subjected to that tariff. As a member of MISO, UE’s transmission rate is calculated in accordance with the MISO tariff rate formula. The transmission rate is updated in June of each year based on UE’s filing with FERC. This rate is charged directly to wholesale customers. This rate is not directly charged to Missouri retail customers because in Missouri the MoPSC includes transmission-related costs in setting bundled retail rates.

Natural Gas

All of UE’s natural gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2010. In January 2011, the MoPSC approved a stipulation and agreement that allows UE to increase annual natural gas revenues by $9 million resolving a June 2010 rate increase request. The new rates became effective on February 20, 2011. As part of the stipulation and agreement, UE agreed not to file a separate natural gas rate increase request before December 31, 2012; however, UE can file a combined natural gas and electric rate case before that date. Further, this agreement does not prevent UE from filing to recover infrastructure replacement costs through an ISRS during this moratorium. The return on equity to be used by UE for purposes of an ISRS tariff filing is 10%.

If certain criteria are met, UE’s natural 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 natural gas infrastructure replacement costs to be passed directly to the consumer.

For additional information on Missouri rate matters, including UE’s 2011 natural gas rate order, UE’s pending electric rate case, and UE’s 2009 and 2010 electric rate orders and related court appeals and regulatory proceedings, 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 under Part II, Item 8, of this report.

Ameren Illinois (AIC)

All of AIC’s electric and natural gas operating revenues were subject to regulation by the ICC or FERC in the year ended December 31, 2010.

Under the Illinois Customer Choice Law, all electric customers in Illinois may choose their own electric energy provider. However, AIC is required to serve as the provider of last resort (POLR) for electric customers within its territory who have not chosen an alternative retail electric supplier. AIC’s obligation to provide full requirements electric service, including power supply, as a POLR varies by customer size. AIC is not required to offer fixed-priced electric service to customers with electric demands of 400 kilowatts or greater, as the market for service to this group of customers has been declared competitive. Power procurement costs incurred by AIC are passed directly to its customers through a cost recovery mechanism.

In April 2010, the ICC issued a rate order for AIC, which was amended in May 2010, that approved a net increase in annual revenues for electric delivery service of $35 million and a net decrease in annual revenues for natural gas delivery service of $20 million. The rate changes became effective in May 2010. The ICC order confirmed the previously approved 80% allocation of fixed non-volumetric residential and commercial natural gas customer charges, and approved a higher percentage of recovery of fixed non-volumetric electric residential and commercial customer charges. The percentage of costs to be recovered through fixed non-volumetric electric residential and commercial customer and meter charges increased from 27% to 40%. AIC and certain intervenors were granted a rehearing with the ICC. In November 2010, the ICC approved an order on the rehearing issues, which authorized an increase in annual revenues of $25 million, in addition to the net $15 million increase authorized in the ICC’s May 2010 amended rate order. The overall annual delivery service revenue increase as a result of these orders is $40 million. The rate changes relating to the rehearing issues became effective on November 19, 2010.

AIC filed a request with the ICC in February 2011 to increase its annual revenues for electric and natural gas delivery service by $60 million and $51 million, respectively. In an attempt to limit regulatory lag, AIC is using a future test year, 2012, in this rate request. Additionally, AIC is requesting a rider mechanism for its pension costs and the continuation of existing riders described below, including cost recovery mechanisms for energy efficiency costs. The requested pension cost rider mechanism would allow AIC to recover from or refund to customers any difference between pension expense incurred and the amount allowed in rates annually without a formal regulatory proceeding.

AIC has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are recovered from a trust fund established when Ameren acquired IP. At December 31, 2010, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, AIC will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under

the tariff rider. Following the AIC Merger, this rider is only applicable for claims that occurred within IP’s historical service territory. Similarly, the rider will seek recovery only from customers within IP’s historical service territory.

In 2009, a new law became effective in Illinois that allows electric and natural gas utilities to recover through a rate adjustment the difference between their actual bad debt expense and the bad debt expense included in their base rates. In February 2010, the ICC approved AIC’s electric and natural gas rate adjustment tariffs to recover bad debt expense not recovered in base rates.

If certain criteria are met, AIC’s natural 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.

FERC regulates the rates charged and the terms and conditions for electric transmission services. Each RTO separately files a regional transmission tariff for approval by FERC. All transmission service within that RTO is then subjected to that tariff. As a member of MISO, AIC’s transmission rate is calculated in accordance with the MISO tariff rate formula. The transmission rate is updated in June of each year based on AIC’s filings with FERC filings. This rate is charged directly to wholesale customers and alternative retail electric suppliers. For retail customers who have not chosen an alternative retail electric supplier, the transmission rate is collected through a rider mechanism.

For additional information on Illinois rate matters, including AIC’s currently pending electric and natural gas rate cases, 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 under Part II, Item 8, of this report.

Merchant Generation

Merchant Generation revenues are determined by market conditions and contractual arrangements. We expect the Merchant Generation fleet of assets to have 6,263 megawatts of capacity available for the 2011 peak summer electrical demand. As discussed below, Genco and AERG sell all of their power and capacity to Marketing Company through power supply agreements. Marketing Company attempts to optimize the value of those assets and mitigate risks through 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, PJM and investor-owned utilities, such as AIC. For additional information on Marketing Company’s hedging activities and Marketing Company’s sales to AIC, see Outlook in Management’s

Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and Note 7 – Derivative Financial Instruments and Note 14 – Related Party Transactions under Part II, Item 8, of this report.

General Regulatory Matters

UE and AIC 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 and AERG 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 the MoPSC and the ICC 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 the 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. In June 2008, UE filed a relicensing application with FERC to operate its Taum Sauk pumped-storage hydroelectric facility for another 40 years. The existing FERC license expired on June 30, 2010. On July 2, 2010, UE received a license extension that allows Taum Sauk to continue operations until FERC issues a new license. UE conducted studies using current field data and submitted the study results to multiple state and federal agencies in February 2011. UE anticipates filing the study results with FERC in the spring of 2011. A FERC order is expected after a review of the study results is completed; however, we cannot predict the ultimate outcome of the order. Taum Sauk returned to service in April 2010 after the plant was rebuilt following the breach of its 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 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 environmental statutes and regulations include requirements for 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 and the management of waste and byproduct materials. 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 or we could be ordered by the courts to pay private parties. Except as indicated in this report, we believe that we are in material compliance with existing statutes and regulations.

In addition to existing laws and regulations governing our facilities, the EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, UE and Genco, that operate coal-fired power plants. Significant new rules already proposed or promulgated within the past year include the regulation of greenhouse gas emissions; revised ambient air quality standards for SO₂ and NO_x emissions, lowering the existing ozone ambient air quality standard; the CATR, which would require further reduction of SO₂ and NO_x emissions from power plants; and a regulation governing coal ash impoundments. Within the next year, the EPA is also expected to propose new regulations under the Clean Water Act that could require significant capital expenditures, such as new water intake structures or cooling towers at our power plants, and a MACT standard for the control of hazardous air pollutants, such as mercury and acid gases from power plants. Such new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many details of these future regulations are unknown, the combined effect of the new and proposed environmental regulations may result in significant capital expenditures or increased operating costs over the next five to eight years for Ameren, UE and Genco. Actions required to ensure that our facilities and operations are in compliance with environmental laws and regulations could be prohibitively expensive. As a result, these regulations could require us to close or to significantly alter the operation of our generating facilities, which could have an adverse effect on our results of operations, financial position, and liquidity.

For additional discussion of environmental matters, including NO_x, SO₂, and mercury emission reduction requirements, global climate change, remediation efforts, UE’s receipt in January 2010 of a Notice of Violation from the EPA alleging violations of the Clean Air Act’s NSR and Title V Programs, and the complaint filed by the EPA

against UE in January 2011 alleging violation of the Clean Air Act and Missouri law in performing projects at UE’s Rush Island coal-fired generating facility, 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 under Part II, Item 8, of this report.

TRANSMISSION AND SUPPLY OF ELECTRIC POWER

Ameren owns an integrated transmission system that comprises the transmission assets of UE, AIC and ATXI. Ameren also operates two balancing authority areas, AMMO (which includes UE) and AMIL (which includes AIC, ATXI, Genco, excluding EEI and Genco’s Elgin CT facility, and AERG). During 2010, the peak demand in AMMO was 8,797 MW and in AMIL was 9,166 MW. The Ameren transmission system directly connects with 15 other balancing authority areas for the exchange of electric energy.

UE, AIC and ATXI are transmission-owning members of MISO. Transmission service on the Ameren 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, the Tennessee Valley Authority, and Louisville Gas and Electric Company. EEI’s generating units are dispatched separately from those of UE, Genco and AERG.

On August 2, 2010, Ameren announced the formation of ATX. ATX intends to build projects initially within Illinois and Missouri, with the potential for expanding to other areas in the future. ATX’s initial investments are expected to be the Grand Rivers projects, the first of which involves building a 345 kilovolt line across the state of Illinois, from the Missouri border to the Indiana border. The investment could total more than $1.3 billion through 2021, with a potential investment of $265 million from 2011 to 2015.

The Ameren Companies and EEI are members of SERC. SERC is responsible for the bulk electric power supply system in many 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. As a result of the Energy Policy Act of 2005, owners and operators of the bulk electric power system are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and its regional entities, such as SERC, and enforced by FERC. The Ameren Companies must follow these standards, which are in place to require that proper functions are performed to ensure the reliability of the bulk electric power system.

See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.

Ameren Missouri (UE)

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 fulfillment of renewable energy requirements, 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.

UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. UE’s integrated resource plan filed with the MoPSC in February 2011 included the expectation that new baseload generation capacity would be required between 2020 and 2030. Because of the significant time required to plan, acquire permits for, and build a baseload power plant, UE continues to study future plant alternatives, as well as energy efficiency programs that could help defer new plant construction. To prepare for the long-term need for baseload capacity, and to prepare for potentially more stringent environmental regulation of coal-fired power plants, which could lead to the retirement of current baseload assets, UE is taking steps to preserve options to meet future demand. These steps include seeking improvements in regulatory treatment of energy efficiency investments, evaluating potential sites for natural gas-fired generation, and pursuing an ESP for an additional unit at its existing nuclear plant site, subject to passage of state legislation that would ensure rate recovery of the ESP costs once the ESP has been approved by the NRC. In December 2010 and January 2011, the Missouri Energy Partnership Act was separately introduced in both the Missouri Senate and House of Representatives. The purpose of this legislation is to maintain an option for nuclear power in the state of Missouri, recover the costs of the ESP for a period up to 20 years, and provide appropriate consumer protections. This legislation remains pending as of the date of this report.

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 under Part II, Item 8, of this report.

Ameren Illinois (AIC)

AIC is required to obtain from market sources all electric supply requirements for customers, except those customers in markets declared competitive, who do not purchase electric supply from third-party suppliers. The power procurement costs incurred by AIC are passed directly to its customers through a cost recovery mechanism.

As part of the 2007 Illinois Electric Settlement Agreement, a new competitive power procurement process led by the IPA was implemented beginning in January 2009. The IPA administers a RFP process that procures AIC’s expected supply obligation. Since the start of this process, the ICC has approved the outcomes of multiple electric power procurement RFPs for energy, capacity and renewable energy credits covering different time periods.

A portion of the electric power supply required for AIC to satisfy its distribution customers’ requirements is purchased in the RFP process administered by the IPA from Marketing Company on behalf of Genco, AERG and EEI. In addition, as part of the 2007 Illinois Electric Settlement Agreement, AIC 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 its round-the-clock power requirements during the period June 1, 2008, through December 31, 2012, at the market prices relevant 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, Note 14 – Related Party Transactions and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for additional information on power procurement in Illinois.

Merchant Generation

Genco and AERG have entered into power supply agreements with Marketing Company 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. 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. EEI and Marketing Company have entered into a power supply agreement for EEI to sell all of its capacity and energy to Marketing Company. This agreement expires on May 31, 2016. All of Genco’s, AERG’s and EEI’s generating facilities compete for the sale of energy and capacity in the competitive energy markets through Marketing Company. See Note 14 – Related Party Transactions under Part II, Item 8, of this report for additional information.

On September 28, 2010, Resources Company announced that it signed a cooperative agreement with the DOE that could lead to repowering a unit at Genco’s Meredosia plant. This would create the world’s first full-scale, oxy-combustion coal-fired plant designed for permanent CO₂ capture and storage. Ameren and two independent companies will assess the project in phases to validate the project’s scope, cost, schedule and commercial viability. If the first phases are successful and the project has received regulatory approval, Ameren and its partners will initiate the construction necessary to repower the plant.

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, 2010, 2009 and 2008:


	Coal			Nuclear			Natural Gas			Hydroelectric			Oil
Ameren:^(a)
2010		85	%		12	%		1	%		2	%		(b	)%
2009		83			13			1			3			(b	)
2008		85			12			1			2			(b	)
Ameren Missouri (UE):
2010		77	%		19	%		1	%		3	%		-	%
2009		75			21			(b	)		4			-
2008		77			19			1			3			(b	)
Merchant Generation:
2010		98	%		-	%		2	%		-	%		(b	)%
2009		99			-			1			-			(b	)
2008		99			-			1			-			(b	)
Genco:
2010		99	%		-	%		1	%		-	%		(b	)%
2009		100			-			(b	)		-			(b	)
2008		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, 2010, 2009 and 2008:


Cost of Fuels (Dollars per million Btus)	2010		2009		2008
Ameren:
Coal^(a)	$	1.848	$	1.654	$	1.572	^(b)
Nuclear		0.701		0.620		0.493
Natural gas^(c)		6.539		8.685		10.503
Weighted average – all fuels^(d)	$	1.803	$	1.591	$	1.573	^(b)
Ameren Missouri (UE):
Coal^(a)	$	1.675	$	1.534	$	1.426
Nuclear		0.701		0.620		0.493
Natural gas^(c)		6.199		8.544		10.264
Weighted average – all fuels^(d)	$	1.563	$	1.386	$	1.340
Merchant Generation:
Coal^(a)	$	2.063	$	1.813	$	1.746	^(b)
Natural gas^(c)		6.972		8.796		10.764
Weighted average – all fuels^(d)	$	2.169	$	1.934	$	1.919	^(b)
Genco:
Coal^(a)	$	2.112	$	1.869	$	1.786
Natural gas^(c)		7.881		13.159		15.857
Weighted average – all fuels^(d)	$	2.206	$	1.957	$	1.896

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

(b)	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.

(c)

The fuel cost for natural gas represents the cost of natural gas and firm 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.

(d)

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.

Coal

Ameren, UE and Genco have agreements in place to purchase a portion of their coal needs and to transport it to electric generating facilities through 2019. Ameren, UE and Genco expect to enter into additional contracts to purchase coal from time to time. Coal supply agreements typically have an initial term of up to five years, with about 20% of the contracts expiring annually. UE has an ongoing need for coal to serve its native load customers and pursues a price hedging strategy consistent with this requirement. Merchant Generation’s forward coal requirements are dependent on the volume of power sales that have been contracted. As such, Merchant Generation strives to achieve increased margin certainty by aligning its fuel purchases with its power sales. Ameren burned 39 million tons (UE – 22 million, Genco – 13 million) of coal in 2010. See Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about coal supply contracts.

About 97% of Ameren’s coal (UE – 97%, Genco – 97%) is purchased from the Powder River Basin in Wyoming. The remaining coal is typically purchased from the Illinois Basin. Ameren, UE and Genco have a goal to maintain coal inventory consistent with their risk management policies. Inventory may be adjusted because of changes in burn or 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 occasionally been restricted because of rail maintenance, weather, and derailments. As of December 31, 2010, coal inventories for Ameren, UE and Genco were at targeted levels. However, in 2011 Merchant Generation is targeting a reduction in its coal inventory, relative to previous levels. Disruptions in coal deliveries could cause Ameren, UE and Genco 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

The steps in the process to provide nuclear fuel generally involve the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride gas, the enrichment of that gas, and 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 2011 fall refueling at UE’s Callaway nuclear plant are scheduled for manufacture and

delivery to the plant during May to July 2011. UE also has agreements or inventories to price-hedge approximately 98%, 84%, and 71% of Callaway’s 2011, 2013, and 2014 refueling requirements, respectively. 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 2013. Fuel fabrication services are under contract through 2014. 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, enhance diversification and pursue opportunities for volume discounts. The Callaway nuclear plant normally requires refueling at 18-month intervals. The last refueling was completed in May 2010. There is no refueling scheduled for 2012 and 2015. 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 and Genco 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’s and Genco’s natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to their generating units. This is accomplished by optimizing transportation and storage options and minimizing cost and price risk through various supply and price-hedging agreements that allow access to multiple gas pools, supply basins, and storage services. As of December 31, 2010, UE had price-hedged about 30% and Genco had price-hedged 84% of its expected natural gas supply requirements for generation in 2011.

Renewable Energy

Illinois and Missouri have enacted laws requiring electric utilities to include renewable energy resources in their portfolios. Illinois requires renewable energy resources to equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers as of June 1, 2008, increasing to 15% by June 1, 2015, and to 25% by June 1, 2025. AIC has procured renewable energy credits under the IPA-administered procurement process to

meet the renewable energy portfolio requirement through May 2011. In December 2010, AIC entered into a 20-year power purchase agreement with renewable energy suppliers and will begin purchasing power under the agreement starting in June 2012, to help supplement these requirements. Approximately 50% of the 2012 renewable energy requirement will be met through this agreement. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, for additional information about the Illinois power procurement process.

In Missouri, utilities are required to purchase or generate from renewable energy sources electricity equaling at least 2% of native load sales, with that percentage increasing to at least 15% by 2021, subject to a 1% limit on customer rate impacts. At least 2% of each renewable energy portfolio requirement must be derived from solar energy. UE expects to satisfy the nonsolar requirement through 2017 with existing renewable generation in its current fleet along with a 15-year, 102-MW power purchase agreement with a wind farm operator in Iowa that became effective in 2009 and the landfill gas project discussed below. Currently, UE expects to meet the solar energy requirement through the purchase of solar-generated renewable energy credits.

In September 2009, UE announced an agreement with a landfill owner to install CTs at a landfill site in St. Louis County, Missouri, which is expected to generate approximately 15MW of electricity by burning methane gas collected from the landfill. Site preparation for the CTs began in 2010 and construction will begin in 2011. The CTs are expected to begin generating power in 2012. UE signed a 20-year supply agreement with the landfill owner to purchase methane gas.

Energy Efficiency

Ameren’s regulated utilities have implemented energy efficiency programs to educate and help their customers become more efficient users of energy. A law in Missouri allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs. The law could, among other things, allow UE to earn a return on its energy efficiency programs equivalent to the return UE could earn with supply-side capital investments, such as new power plants. UE introduced multiple energy efficiency programs in 2009 and 2010. UE has set up a website at www.uefficiency.com in order to provide more information to its customers regarding energy efficiency.

AIC is participating in the Illinois Clean Energy Community Foundation, a program that supports energy efficiency, promotes renewable energy, and provides educational opportunities. In 2008, the ICC issued orders approving AIC’s electric energy efficiency plan as well as cost recovery mechanisms by which program costs are being recovered from customers. AIC has set up a website at www.actonenergy.com in order to provide more information to its customers regarding energy efficiency.

NATURAL GAS SUPPLY FOR DISTRIBUTION

UE and AIC are responsible for the purchase and delivery of natural gas to their gas utility customers. UE and AIC 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 and AIC primarily use the Panhandle Eastern Pipe Line Company, the Trunkline Gas Company, the Natural Gas Pipeline Company of America, the Mississippi River Transmission Corporation, the Northern Border Pipeline Company 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 and AIC in Missouri and Illinois under PGA clauses, subject to prudency reviews by the MoPSC and the ICC. As of December 31, 2010, UE had price-hedged 90%, and AIC had price-hedged 89%, of its expected natural gas supply requirements for distribution in 2011.

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 10 – Callaway Nuclear Plant, Note 14 – Related Party Transactions, and Note 15 – Commitments and Contingencies under Part II, Item 8.

INDUSTRY ISSUES

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

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

political and regulatory resistance to higher rates, especially in a difficult 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, supply and distribution, including new technologies;

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

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 such as 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 merchant generating and independent transmission entities and RTOs;

increases, decreases and volatility in power prices due to the balance of supply and demand and marginal fuel costs;

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

the availability of qualified labor and material, and rising costs;

regulatory lag;

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

public concern about the siting of new facilities;

aging infrastructure and the need to construct new power generation, transmission and distribution 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 natural 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 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,	2010			2009			2008
Electric Sales – kilowatthours (in millions):
Ameren Missouri:
Residential		14,640			13,413			13,904
Commercial		15,002			14,510			14,690
Industrial		8,656			7,037			9,256
Other		1,429			1,655			785
Native load subtotal		39,727			36,615			38,635
Off-system sales		8,496			12,447			10,457
Subtotal		48,223			49,062			49,092
Ameren Illinois:
Residential
Power supply and delivery service		12,341			11,089			11,667
Commercial
Power supply and delivery service		4,419			5,235			6,095
Delivery service only		8,051			6,797			6,147
Industrial
Power supply and delivery service		1,389			514			1,442
Delivery service only		11,147			10,712			11,300
Other		545			546			555
Native load subtotal		37,892			34,893			37,206
Merchant Generation:
Nonaffiliate energy sales		30,788			25,673			26,395
Affiliate native energy sales		949			3,529			6,055
Subtotal		31,737			29,202			32,450
Eliminate affiliate sales		(949	)		(3,529	)		(6,055	)
Eliminate Ameren Illinois/Merchant Generation common customers		(5,016	)		(5,566	)		(4,939	)
Ameren total		111,887			104,062			107,754
Electric Operating Revenues (in millions):
Ameren Missouri:
Residential	$	1,193		$	982		$	948
Commercial		1,004			881			838
Industrial		399			314			372
Other		147			122			108
Native load subtotal	$	2,743		$	2,299		$	2,266
Off-system sales		287			401			490
Subtotal	$	3,030		$	2,700		$	2,756
Ameren Illinois:
Residential
Power supply and delivery service	$	1,270		$	1,094		$	1,112
Commercial
Power supply and delivery service		425			521			616
Delivery service only		143			103			77
Industrial
Power supply and delivery service		66			22			102
Delivery service only		38			36			30
Other		119			189			305
Native load subtotal	$	2,061		$	1,965		$	2,242
Merchant Generation:
Nonaffiliate energy sales	$	1,442		$	1,340		$	1,389
Affiliate native energy sales		231			385			441
Other		20			(15	)		106
Subtotal	$	1,693		$	1,710		$	1,936
Eliminate affiliate revenues		(263	)		(435	)		(547	)
Ameren total	$	6,521		$	5,940		$	6,387


Electric Operating Statistics – Year Ended December 31,	2010			2009			2008
Electric Generation – megawatthours (in millions):
Ameren Missouri		48.1			48.7			49.3
Merchant Generation:
Genco		22.0			20.5			24.6
AERG		7.5			6.8			6.7
Medina Valley		0.1			0.2			0.2
Subtotal		29.6			27.5			31.5
Ameren total		77.7			76.2			80.8
Price per ton of delivered coal (average)	$	32.91		$	29.85		$	26.90	^(a)
Source of energy supply:
Coal		65.7	%		67.0	%		70.1	%
Nuclear		8.9			10.8			9.5
Hydroelectric		1.6			2.0			1.8
Gas		1.0			0.6			0.8
Purchased – Wind		0.3			0.1			-
Purchased – Other		22.5			19.5			17.8
		100.0	%		100.0	%		100.0	%


Gas Operating Statistics – Year Ended December 31,	2010			2009			2008
Gas Sales (millions of Dth)
Ameren Missouri:
Residential		7			7			8
Commercial		4			4			4
Industrial		1			1			1
Subtotal		12			12			13
Ameren Illinois:
Residential		60			60			65
Commercial		23			26			28
Industrial		7			7			11
Subtotal		90			93			104
Other:
Industrial		1			3			4
Subtotal		1			3			4
Eliminate affiliate sales		-			-			(1	)
Ameren total		103			108			120
Natural Gas Operating Revenues (in millions)
Ameren Missouri:
Residential	$	100		$	106		$	121
Commercial		43			47			54
Industrial		10			10			12
Other		13			7			14
Subtotal	$	166		$	170		$	201
Ameren Illinois:
Residential	$	649		$	646		$	819
Commercial		223			259			338
Industrial		44			38			119
Other		37			72			(11	)
Subtotal	$	953		$	1,015		$	1,265
Other:
Industrial	$	4		$	15		$	26
Subtotal	$	4		$	15		$	26
Eliminate affiliate revenues		(6	)		(5	)		(10	)
Ameren total	$	1,117		$	1,195		$	1,482

Gas Operating Statistics – Year Ended December 31,

2010

2009

2008

Peak day throughput (thousands of Dth):

167

163

158

AIC

1,227

1,353

1,280

Total peak day throughput

1,394

1,516

1,438

(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 under Part II, Item 8, of this report.

AVAILABLE INFORMATION

The Ameren Companies make available free of charge through Ameren’s website (www.ameren.com) their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Ameren’s eXtensible Business Reporting Language (XBRL) documents, and any amendments to those reports filed or furnished pursuant to Sections 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 website maintained by the SEC (www.sec.gov). Ameren also uses its website (www.ameren.com) as a channel of distribution of material information relating to the Ameren Companies. Financial and other material information regarding the Ameren Companies is routinely posted and accessible at Ameren’s website.

The Ameren Companies also make available free of charge through Ameren’s website (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 and environmental 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. The information on Ameren’s website, or any other website referenced in this report, is not incorporated by reference into this report.

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 results of operations, financial position, and liquidity of the Ameren Companies. See Forward-looking Statements above and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report.

We are subject to extensive regulation of our businesses, which could adversely affect our results of operations, financial position, and liquidity.

We are subject to, or affected by, extensive federal and state regulation. This extensive regulatory framework, some but not all of which is more specifically identified in the following risk factors, regulates, among other matters, the electric and natural gas industries; rate and cost structure of utilities; operation of nuclear power facilities; construction and operation of generation, transmission and distribution facilities; acquisition, disposal, depreciation and amortization of assets and facilities; transmission reliability; and present or prospective wholesale and retail competition. We must address in our business planning and management of operations the effects of existing and proposed laws and regulations and potential changes in the regulatory framework, including initiatives by federal and state legislatures, RTOs, utility regulators, and taxing authorities. Significant changes in the nature of the regulation of our businesses could require changes to our business planning and management of our businesses and could adversely affect our results of operations, financial position, and liquidity. Failure to obtain adequate rates or regulatory approvals in a timely manner, failure to obtain necessary licenses or permits from regulatory authorities, new or changed laws, regulations, standards, interpretations, or other legal requirements, or increased compliance costs could adversely impact our results of operations, financial position, and liquidity.

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

prudency of expenditures, 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 are largely outside of UE’s and AIC’s control. Regulatory lag involved in filing and getting new rates approved could have a material adverse effect on our results of operations, financial position, and liquidity. Rate orders are also subject to appeal and stay requests, which create additional uncertainty as to the rates UE and AIC will ultimately be allowed to charge for their services.

UE and AIC electric and natural gas utility rates are typically established in regulatory proceedings that take up to 11 months to complete. Rates established in those proceedings for UE are primarily based on historical costs and revenues. Rates established in those proceedings for AIC may be based on historical or estimated future costs and revenues. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rates include an allowed return on investments by the regulators. Although rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all the costs of UE and AIC to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs or an adequate return on those investments.

During periods of rising costs and investments or declining retail usage, UE and AIC may not be able to earn the allowed return established by their regulators. This could result in deferral or elimination of planned capital investments. As a result, UE and AIC expect to file rate cases frequently. A period of increasing rates for our customers, especially during weak economic times, could result in additional regulatory and legislative actions, as well as competitive and political pressures, which could have a material adverse effect on our results of operations, financial position, and liquidity.

We are subject to various environmental laws and regulations that require significant capital expenditures or could result in closure of facilities, could increase our operating costs, and could adversely influence or limit our results of operations, financial position, and liquidity, or expose us to 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 facilities, and natural gas transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, 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.

In addition to existing laws and regulations governing our facilities, the EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, UE and Genco that operate coal-fired power plants. Significant new rules already proposed or promulgated within the past year include the regulation of greenhouse gas emissions; revised ambient air quality standards for SO₂ and NO_x emissions that increase the stringency of the existing ozone ambient air quality standard; the CATR, which would require further reduction of SO₂ and NO_x emissions from power plants; and a regulation governing coal ash impoundments. Within the next year, the EPA is also expected to propose new regulations under the Clean Water Act, which could require significant capital expenditures such as new water intake structures or cooling towers at our power plants; NSPS and emission guidelines for greenhouse gas emissions applicable to new and existing electric generating units; and a MACT standard for the control of hazardous air pollutants such as mercury and acid gases from power plants. Such new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many of the details of these future regulations are unknown, the combined effect of the new and proposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to eight years for Ameren, UE and Genco. Actions required to ensure that our facilities and operations are in compliance with environmental laws and regulations could be prohibitively expensive. As a result, these regulations could require us to close or to significantly alter the operation of our generating 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.

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.

Ameren also may be subject to risks in connection with changing or conflicting interpretations of existing laws and regulations. The EPA is engaged in an enforcement initiative targeted at coal-fired power plants in the United States to determine whether coal-fired power plants failed to comply

with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications. Failure to comply with the NSR and NSPS provisions under the Clean Air Act can result in increased capital expenditures for the installation of control technology, increased operations and maintenance expenses, and fines or penalties. Ameren and Genco have received requests for information from the EPA pursuant to Section 114(a) of the Clean Air Act. In January 2010, UE received a Notice of Violation from the EPA alleging violations of the Clean Air Act’s NSR and Title V programs. In the Notice of Violation, the EPA contends that various projects at UE’s Labadie, Meramec, Rush Island, and Sioux coal-fired power plant facilities, dating back to the mid-1990s, triggered NSR requirements. In October 2010, the EPA supplemented and amended the Notice of Violation to include additional projects at UE’s coal-fired power plant facilities. The amended Notice of Violation followed a series of information requests under Section 114(a). In January 2011, the EPA filed a complaint against UE in the United States District Court for the Eastern District of Missouri. The EPA’s complaint alleges that in performing projects at its Rush Island coal-fired generating facility, UE violated provisions of the Clean Air Act and Missouri law. At present, the complaint does not include UE’s other coal-fired facilities. Litigation of this matter could take many years to resolve. An outcome in this matter adverse to UE could require substantial capital expenditures and the payment of substantial penalties, neither of which can be determined at this time. Such expenditures could affect unit retirement and replacement decisions and our results of operations, financial position, and liquidity if such costs are not recovered through regulated rates.

Ameren, UE and Genco have incurred and expect to incur significant costs related to environmental compliance and site remediation. 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 facilities for Ameren, UE and Genco. 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 cost recovery mechanism for Genco or for Ameren’s Merchant Generation business segment. We are unable to predict the ultimate impact of these matters on our results of operations, financial position, and liquidity.

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

Initiatives to limit greenhouse gas emissions and to address climate change have been subject to consideration in the U.S. Congress. In the past two years, legislation has been passed in the U.S. House of Representatives and

proposed in the Senate to reduce greenhouse gas emissions from designated sources, including coal-fired electric generation units. Many of these proposals have included economy-wide cap-and-trade programs. The reduction of greenhouse gas emissions has been identified as a high priority by President Obama’s administration.

Potential impacts from climate change legislation could vary, depending upon proposed CO₂ emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. Our emissions of greenhouse gases vary among our generating facilities, but coal-fired power plants are significant sources of CO₂. Ameren’s analysis shows that if most versions of the recently proposed climate change bills were enacted into law, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and upon the economy in the Midwest because of the region’s reliance on electricity generated by coal-fired power plants. Natural gas emits per kilowatthour about half as much CO₂ as coal emits when burned to produce electricity. Therefore, climate change regulation could cause the conversion of coal-fired power plants to natural gas, or the construction of new natural gas plants to replace coal-fired power plants. As a result, economy-wide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas. Higher costs for energy could contribute to reduced demand for electricity and natural gas.

In December 2009, the EPA issued its “endangerment finding” determining that greenhouse gas emissions, including CO₂, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act in 2011. As a result of these actions, we will be required to consider the emissions of greenhouse gas in any air permit application submitted by us or pending after January 1, 2011.

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA finalized in May 2010 regulations known as the “Tailoring Rule,” that would establish new higher thresholds for regulating greenhouse gas emissions from stationary sources, such as power plants. The Tailoring Rule became effective in January 2011. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to their permits upon renewal. Currently, all Ameren power plants have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases of at least 75,000 tons per year, measured as CO₂ equivalents, such

projects could trigger permitting requirements under the NSR/Prevention of Significant Deterioration program and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources also would be required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. Separately, in December 2010, the EPA announced it would establish NSPS for greenhouse gas emissions at new and existing fossil-fuel fired power plants. In the announcement, the EPA said it will propose standards for power plants in July 2011 and issue final standards in May 2012. It is uncertain whether reductions to greenhouse gas emissions would be required at our power plants as a result of any of the EPA’s new and future rules. Legal challenges to the EPA’s greenhouse gas rules have been filed and more challenges are expected. Any federal climate change legislation that is enacted may preempt the EPA’s regulation of greenhouse gas emissions, including the Tailoring Rule, particularly as it relates to power plant greenhouse gas emissions. The extent to which the Tailoring Rule could have a material impact on our generating facilities depends upon how state agencies apply the EPA’s guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants, whether physical changes or changes in operations subject to the rule occur at our power plants, and whether federal legislation that preempts the rule is passed.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent UE requests recovery of these costs through rates, its regulators might deny some or all of, or defer timely recovery of, these costs. Excessive costs to comply with future legislation or regulations might force Ameren, UE and Genco as well as other similarly situated electric power generators to close some coal-fired facilities and could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren’s, UE’s, and Genco’s results of operations, financial position, and liquidity.

The construction of, and capital improvements to, Ameren’s, UE’s and AIC’s electric and gas utility infrastructure as well as to Ameren’s and Genco’s merchant generation facilities involve substantial risks. These risks include escalating costs, unsatisfactory performance by the projects when completed, the inability to complete projects as scheduled, cost disallowances by regulators and the inability to earn a reasonable return on invested capital, any of which could result in higher costs and the closure of facilities.

Over the next five years, the Ameren Companies will incur significant capital expenditures to comply with existing and known environmental regulations and to make investments in their electric and gas natural utility infrastructure and their merchant generation facilities. The

Ameren Companies estimate that they will incur up to $8.2 billion (UE – up to $4.1 billion; AIC – up to $2.4 billion; Genco – up to $1.0 billion; other – up to $700 million) of capital expenditures during the period 2011 through 2015. These expenses include construction expenditures, capitalized interest or allowance for funds used during construction, and compliance with environmental standards. Construction costs as well as the cost of capital have escalated in recent years. They are expected to stay at current levels or to escalate further.

Investments in Ameren’s regulated operations are expected to be recoverable from ratepayers, but are subject to prudency reviews and regulatory lag. The recoverability of amounts expended in merchant generation operations will depend upon market prices for capacity and energy.

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 who do not perform 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 that could occur 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 to the loss of their investment in the project or facility. The Ameren Companies may also be required to purchase electricity 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, and 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, credit, 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 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, and liquidity could otherwise be adversely affected.

Certain of the Ameren Companies have obligations to other Ameren Companies or other Ameren subsidiaries as a result of transactions involving energy, coal, other commodities and services, and as a result 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, and liquidity could be adversely affected, resulting in the nondefaulting Ameren entity being unable to meet its obligations, including to unrelated third parties.

Increasing costs associated with our defined benefit retirement and postretirement plans, health care plans, and other employee benefits could materially adversely affect our results of operations, financial position, and liquidity.

We offer defined benefit retirement 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 to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at December 31, 2010, its investment performance in 2010, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $110 million in each of the next five years, with aggregate estimated contributions of $470 million. We expect UE’s, AIC’s, and Genco’s portion of the future funding requirements to be 63%, 28%, and 9%, respectively. These amounts are estimates. They may change with actual investment performance, changes in interest rates, changes in our assumptions, 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 could increase our financing needs and otherwise materially adversely affect our results of operations, financial position, and liquidity.

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

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:

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

longer-than-anticipated maintenance outages;

older generating equipment may require significant expenditures to keep it operating at peak efficiency;

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

lack of water for cooling plant operations;

labor disputes;

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

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

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

unusual or adverse weather conditions, including severe storms, droughts, 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 systems where sensitive utility customer data and account information are stored;

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

limitations on amounts of insurance available to cover losses that might arise in connection with operating our electric generating, transmission, and distribution facilities; and

other unanticipated operations and maintenance expenses and liabilities.

We are subject to federal regulatory compliance and proceedings, which increase our risk of regulatory penalties and other sanctions.

The Energy Policy Act of 2005 increased FERC’s civil penalty authority for violation of FERC statutes, rules and orders. FERC can now impose penalties of $1 million per violation per day. Under the Energy Policy Act of 2005, the Ameren Companies, as owners and operators of bulk power transmission systems and/or electric generation facilities, are subject to mandatory reliability standards. Compliance with these mandatory reliability standards may subject the Ameren Companies to higher operating costs and may result in increased capital expenditures. If the Ameren Companies were found not to be in compliance with these mandatory reliability standards or other FERC statutes, rules and orders, the Ameren Companies may incur substantial monetary penalties and other sanctions, which could adversely affect their results of operations, financial position, and liquidity.

Our natural gas distribution and storage activities involve numerous risks that may result in accidents and other operating risks and costs that could materially adversely affect our results of operations, financial position, and liquidity.

Inherent in our natural gas distribution and storage activities are a variety of hazards and operating risks, such as leaks, accidental explosions, and mechanical problems, which could cause substantial financial losses. In addition,

these risks could result in serious injury to employees and nonemployees, loss of human life, significant damage to property, environmental pollution and impairment of our operations, which in turn could lead to substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The location of distribution lines and storage facilities near populated areas, including residential areas, commercial business centers, industrial sites, and other public gathering places, could increase the level of damages resulting from these risks. The occurrence of any of these events not fully covered by insurance could materially adversely affect our results of operations, financial position, and liquidity.

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 a material 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 settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident.

UE had property and liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Insurance did not cover some lost electric margins and penalties paid to FERC. UE believes that the total cost for cleanup, damage, and liabilities, excluding costs to rebuild the upper reservoir, is approximately $207 million, which is the amount UE paid as of December 31, 2010.

In June 2010, UE sued an insurance company that was providing UE with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the U.S. District Court for the Eastern District of Missouri, UE claimed the insurance company breached its duty to indemnify UE for the losses experienced from the incident. In January 2011, a federal judge ruled that the parties must first pursue alternative dispute resolution under the terms of their coverage agreement. In February 2011, UE filed an appeal of the January ruling to the U.S. Court of Appeals for the Eighth District, which seeks resolution outside of a dispute resolution process.

Until Ameren’s remaining liability insurance claims and the related litigation are resolved, among other things, we are unable to determine the total impact the breach could have on Ameren’s and UE’s results of operations, financial position, and liquidity beyond those amounts already recognized.

The recoverability of any Taum Sauk facility rebuild costs from customers is subject to the terms and conditions set forth in UE’s November 2007 state of

Missouri settlement agreement. In that settlement, UE agreed that it would not attempt to recover from ratepayers costs incurred in the reconstruction, expressly excluding, however, enhancements, costs incurred due to circumstances or conditions that were not at that time reasonably foreseeable and costs that would have been incurred absent the Taum Sauk incident. Certain costs associated with the Taum Sauk facility not recovered from property insurers may be recoverable from UE’s electric customers through rates established in rate cases filed subsequent to the in-service date of the rebuilt facility. As of December 31, 2010, UE had capitalized in property and plant Taum Sauk-related costs of $89 million that UE believes qualify for recovery in electric rates under the terms of the November 2007 state of Missouri settlement agreement, and those costs were included in UE’s pending electric rate increase request filed in September 2010. The inclusion of such costs in UE’s electric rates is subject to review and approval by the MoPSC. Any amounts not recovered in electric rates, or otherwise, could result in charges to earnings, which could be material.

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

All of Genco’s and AERG’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 merchant subsidiaries generally depend on the prices that can be obtained for energy and capacity in Illinois and adjacent markets by Marketing Company.

Market prices for energy and capacity may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and fuel can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of oversupply, prices might be depressed. Also, at times legislators or regulators with jurisdiction over wholesale and retail energy commodity and transportation rates may impose price limitations, bidding rules, and other mechanisms to address volatility and other issues in these markets.

For power products sold in advance, contract prices are influenced both by market conditions and by the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Marketing Company’s contract portfolio may have average contract prices greater than or less than current market prices, including at the expiration of the contracts, which could significantly affect Ameren’s and Genco’s results of operations, financial condition and liquidity.

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;

current and future prices for emission allowances that may be required to operate the fossil fuel-fired electric generating facilities in compliance with environmental laws and permits;

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 energy-efficiency programs;

climate conditions in the Midwest market and major natural disasters; and

environmental laws and regulations.

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

UE’s ownership of the Callaway nuclear plant subjects it 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 the Callaway nuclear plant 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 or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated from time to time 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, and 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. An incident at a nuclear facility anywhere in the world also could cause the NRC to impose additional conditions or requirements on the industry, which could increase costs and result in additional capital expenditures.

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 at other times exhibit sustained increases or decreases, 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, and liquidity.

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

Like other electric and natural gas utilities and other merchant 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, and liquidity.

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

We use short-term and long-term 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 regulatory lag, we expect to continue to rely on 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 a recession or extreme volatility in global debt or equity capital and credit markets, 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 our ability to draw on bank credit facilities. Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power and gas supply, among other things, which could have a material adverse effect on our results of operations, financial position, and liquidity. 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.

Ameren’s holding company structure could limit its ability to pay common stock dividends and to service its debt obligations.

Ameren is a holding company; 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 ability to service its debt obligations is 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 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 work force 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 discussion of planned additions, replacements or transfers. See also Note 5 – Long-term Debt and Equity Financings, and Note 15 – Commitments and Contingencies 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 2011 peak summer electrical demand:


Primary Fuel Source	Plant	Location	Net Kilowatt Capability^(a)
Ameren Missouri (UE):
Coal	Labadie	Franklin County, Mo.		2,401,000
	Rush Island	Jefferson County, Mo.		1,222,000
	Sioux	St. Charles County, Mo.		968,000
	Meramec	St. Louis County, Mo.		832,000
Total coal				5,423,000
Nuclear	Callaway	Callaway County, Mo.		1,194,000
Hydroelectric	Osage	Lakeside, Mo.		240,000
	Keokuk	Keokuk, Ia.		136,000
Total hydroelectric				376,000
Pumped-storage	Taum Sauk	Reynolds County, Mo.		450,000
Oil (CTs)	Meramec	St. Louis County, Mo.		58,000
	Fairgrounds	Jefferson City, Mo.		54,000
	Mexico	Mexico, Mo.		53,000
	Moberly	Moberly, Mo.		53,000
	Moreau	Jefferson City, Mo.		53,000
	Howard Bend	St. Louis County, Mo.		39,000
	Venice	Venice, Ill.		(b	)
Total oil				310,000
Natural gas (CTs)	Audrain^(c)	Audrain County, Mo.		592,000
	Venice^(d)	Venice, Ill.		487,000
	Goose Creek	Piatt County, Ill.		426,000
	Pinckneyville	Pinckneyville, Ill.		312,000
	Raccoon Creek	Clay County, Ill.		300,000
	Kinmundy^(d)	Kinmundy, Ill.		206,000
	Peno Creek^(c)(d)	Bowling Green, Mo.		188,000
	Meramec^(d)	St. Louis County, Mo.		48,000
	Viaduct	Cape Girardeau, Mo.		25,000
	Kirksville	Kirksville, Mo.		13,000
Total natural gas				2,597,000
Total Ameren Missouri (UE)				10,350,000
Merchant Generation:
Genco:
Coal	Newton	Newton, Ill.		1,186,000
	Joppa Generating Station (EEI)^(e)	Joppa, Ill.		1,002,000
	Coffeen	Coffeen, Ill.		895,000
	Meredosia	Meredosia, Ill.		203,000
	Hutsonville	Hutsonville, Ill.		151,000
Total coal				3,437,000
Oil	Meredosia	Meredosia, Ill.		166,000
	Hutsonville (Diesel)	Hutsonville, Ill.		3,000
Total oil				169,000
Natural gas (CTs)	Grand Tower	Grand Tower, Ill.		511,000
	Elgin	Elgin, Ill.		468,000
	Gibson City^(d)	Gibson City, Ill.		230,000
	Joppa 7B	Joppa, Ill.		162,000
	Columbia^(f)	Columbia, Mo.		108,000
	Joppa (EEI)^(e)	Joppa, Ill.		74,000
Total natural gas				1,553,000
Total Genco				5,159,000
AERG:
Coal	E.D. Edwards	Bartonville, Ill.		650,000
	Duck Creek	Canton, Ill.		410,000
Total AERG				1,060,000
Medina Valley:
Natural gas	Medina Valley	Mossville, Ill.		44,000
Total Merchant Generation				6,263,000
Total Ameren				16,613,000

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

(b)	This facility is in extended reserve shutdown.

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

(d)	One of the four CTs at Gibson City has the capability to operate on either oil or natural gas (dual fuel).

(e)	Genco owns an 80% interest in EEI. This table reflects the full capability of EEI’s facilities.

(f)

In June 2010, Genco completed a sale of 25% of its Columbia CT facility to the city of Columbia, Missouri. Genco received cash proceeds of $18 million from the sale. The city of Columbia also holds two options to purchase additional ownership interests in the facility under two existing power purchase agreements. Columbia can exercise one option, as amended, for an additional 25% of the facility at the end of 2011 for a purchase price of $14.9 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 25% of the facility 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. On an annual basis, the city of Columbia purchases a total of 72 megawatts of capacity and energy generated by the facility under the two existing power purchase agreements. If the city of Columbia exercises one of the purchase options described above, the power purchase agreement associated with that option would be terminated.

The following table presents electric and natural gas utility-related properties for UE and AIC as of December 31, 2010:


	UE			AIC
Circuit miles of electric transmission lines		2,944			4,535
Circuit miles of electric distribution lines		33,031			45,531
Circuit miles of electric distribution lines underground		22	%		15	%
Miles of natural gas transmission and distribution mains		3,268			18,128
Propane-air plants		1			-
Underground gas storage fields		-			12
Billion cubic feet of total working capacity of underground gas storage fields		-			25

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 bonds 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, Medina Valley’s generating facility, certain substations, and most transmission and distribution lines and gas mains are situated on lands occupied 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 and AIC are subject to the first liens of the indentures securing their mortgage bonds.

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 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.

UE operates a CT facility located in Audrain County, Missouri. UE has rights and obligations as lessee of the CT facility under a long-term lease with Audrain County. The lease term will expire on December 1, 2023. Under the terms of this capital lease, UE is responsible for all operation and maintenance 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.

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. Material legal and administrative proceedings, which are discussed in Note 2 – Rate and Regulatory Matters, and Note 15 – Commitment and Contingencies under part II, Item 8, of this report and incorporated herein by reference, include the following:

appeal of the MoPSC January 2009 and May 2010 electric rate orders;

an electric rate case proceeding for UE pending before the MoPSC;

the MoPSC staff’s FAC prudence review pending before the MoPSC;

appeal of the MoPSC rules implementing the Missouri renewable energy portfolio requirement;

appeal of certain aspects of the ICC’s 2010 rate orders;

electric and natural gas rate proceedings for AIC pending before the ICC;

the EPA’s Clean Air Act-related litigation filed against UE and NSR investigations at Genco and AERG;

remediation matters associated with MGP and waste disposal sites of the Ameren Companies;

litigation associated with the breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility; and

asbestos-related litigation associated with Ameren, UE, AIC and Genco.

ITEM 4.

[REMOVED AND RESERVED].

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

The executive officers of the Ameren Companies, including major subsidiaries, as of December 31, 2010, (except as otherwise noted) are listed below, along with their ages as of December 31, 2010, 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	Positions and Offices Held
Thomas R. Voss	63	Chairman, President and Chief Executive Officer, and Director
Voss joined UE in 1969. He was elected senior vice president of UE, CIPS, and Ameren Services in 1999, of Genco in 2001, of 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. In 2006, he was elected executive vice president of UE, CIPS, CILCO and IP. In 2007, Voss was elected chairman, president, and chief executive officer of UE. He relinquished his positions at CIPS, CILCO and IP in 2007. In 2009, Voss was elected president and chief executive officer of Ameren; at that time, he relinquished his other positions. In 2010, the Ameren board of directors elected Voss to the position of chairman of the board. He has been a member of the Ameren board since 2009.

Martin J. Lyons, Jr.	44	Senior Vice President and Chief Financial Officer
Lyons joined Ameren, UE, CIPS, Genco, and Ameren Services in 2001 as controller. He was elected controller of CILCO in 2003. He was also elected vice president of Ameren, UE, CIPS, Genco, CILCO, and Ameren Services in 2003 and vice president and controller of IP in 2004. In 2007, his positions at UE were changed to vice president and principal accounting officer. In 2008, Lyons was elected senior vice president and principal accounting officer of the Ameren Companies. In 2009, Lyons was also elected chief financial officer of the Ameren Companies. With the AIC Merger in 2010, Lyons remained senior vice president, chief financial officer and principal accounting officer at AIC.

Gregory L. Nelson	53	Senior Vice President and General Counsel (Effective March 2, 2011)
Nelson joined UE in 1995 as a manager in the tax department and assumed a similar position with Ameren Services in 1998. Nelson was elected vice president and tax counsel of Ameren Services in 1999 and vice president of UE, CIPS, CILCO and Genco in 2003 and of IP in 2004. In 2010, Nelson was elected vice president, tax and deputy general counsel of Ameren Services and remained vice president of UE, CIPS, CILCO, IP and Genco. With the AIC Merger in 2010, Nelson remained vice president at AIC. Effective March 2, 2011, Nelson will assume the positions of senior vice president and general counsel of Ameren, UE, AIC, Genco and Ameren Services.

Jerre E. Birdsong	56	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 of Genco in 2000. In addition to being treasurer, in 2001 he was elected vice president at Ameren, UE, CIPS, Ameren Services and Genco. Additionally, he was elected vice president and treasurer of CILCO in 2003 and of IP in 2004. With the AIC Merger in 2010, Birdsong, remained vice president and treasurer at AIC.

SUBSIDIARIES:


Name	Age	Positions and Offices Held
Warner L. Baxter	49	Chairman, President and Chief Executive Officer (UE)
Baxter joined UE in 1995. He was elected senior vice president, finance, of Ameren, UE, CIPS, Ameren Services, and Genco in 2001 and of CILCO in 2003. Baxter was elected to the positions of executive vice president and chief financial officer of Ameren, UE, CIPS, Genco, CILCO and Ameren Services in 2003 and of IP in 2004. He was elected chairman, president, chief executive officer and chief financial officer of Ameren Services in 2007. In 2009, Baxter was elected chairman, president and chief executive officer of UE; at that time, he relinquished his other positions.

Maureen A. Borkowski	53	Chairman, President and Chief Executive Officer (ATX)
Borkowski joined UE in 1981. She left the company for a period of time before rejoining Ameren in 2005. Borkowski has led Ameren’s transmission operations since 2005 as vice president, transmission, of Ameren Services. In 2010, Borkowski was elected president and chief executive officer of ATX. Effective March 2, 2011, Borkowski will also assume the position of Chairman of ATX.

Scott A. Cisel	57	Chairman, President and Chief Executive Officer (AIC)
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 positions of vice president and chief operating officer of 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. With the AIC Merger in 2010, Cisel remained chairman, president and chief executive officer at AIC.

Daniel F. Cole	57	Chairman, President and Chief Executive Officer (Ameren Services)
Cole joined UE in 1976. 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 CILCO in 2003 and of IP in 2004. In 2009, Cole was elected chairman, president and chief executive officer of Ameren Services and remained senior vice president of UE, CIPS, CILCO and IP. With the AIC Merger in 2010, Cole remained senior vice president at AIC.

Karen C. Foss	66	Senior Vice President (Ameren Services)
Foss joined UE in 2007 as vice president of public relations. She was elected senior vice president, communications and brand management, of Ameren Services in 2009. Foss relinquished her position at UE in 2009. Prior to joining UE, Foss was a news anchor at KSDK-TV in St. Louis, Missouri. Foss will retire from Ameren Services in July 2011.

Adam C. Heflin	46	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.

Richard J. Mark	55	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, customer operations of UE in 2005, with responsibility for Missouri energy delivery. In 2007, Mark relinquished his position at Ameren Services.

Michael L. Moehn	41	Senior Vice President (Ameren Services)
Moehn joined Ameren Services in 2000. He was named director of Ameren Services’ corporate modeling and transaction support in 2001 and elected vice president of business services for Resources Company in 2002. In 2004, Moehn was elected vice president of corporate planning of Ameren Services and relinquished his position at Resources Company. In 2008, he was elected senior vice president, corporate planning and business risk management of Ameren Services.

Charles D. Naslund	58	Senior Vice President (UE) (Effective March 2, 2011)
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. In 2008, he was elected chairman, president and chief executive officer of Resources Company and chairman and president of Genco. Naslund relinquished his positions at UE in 2008. Effective March 2, 2011, Naslund will assume the position of senior vice president, generation and environmental projects of UE and relinquish his positions of chairman, president and chief executive officer of Resources Company and chairman and president of Genco.


Name	Age	Positions and Offices Held

Andrew M. Serri	49	President and Chief Executive Officer (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 and chief executive officer of Marketing Company that same year. He relinquished his position at Ameren Services in 2007.

Steven R. Sullivan	50	Chairman, President and Chief Executive Officer (Resources Company) and Chairman and President (Genco) (Effective March 2, 2011)
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 CILCO. He was elected to his present positions of senior vice president, general counsel and secretary of Ameren, UE, CIPS, Genco, CILCO and Ameren Services in 2003 and of IP in 2004. With the AIC Merger in 2010, Sullivan remained senior vice president, general counsel and secretary at AIC. Effective March 2, 2011, Sullivan will assume the positions of chairman, president and chief executive officer of Resources Company and chairman and president of Genco and relinquish his positions of senior vice president and general counsel of Ameren, UE, AIC, Genco and Ameren Services. Sullivan remains secretary of Ameren, UE, AIC, Genco and Ameren Services.

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 Karen C. Foss, 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 common shareholders of record totaled 66,808 on January 31, 2011. The following table presents the price ranges, closing prices, and dividends declared per Ameren common share for each quarter during 2010 and 2009.

High

Low

Close

Dividends Declared

AEE 2010 Quarter Ended:

March 31

28.27

24.14

26.08

38¹/2

June 30

26.92

23.09

23.77

38¹/2

September 30

28.99

23.45

28.40

38¹/2

December 31

29.89

27.65

28.19

38¹/2

AEE 2009 Quarter Ended:

March 31

35.35

19.51

23.19

38¹/2

June 30

25.25

21.75

24.89

38¹/2

September 30

27.66

23.09

25.28

38¹/2

December 31

28.67

23.78

27.95

38¹/2

There is no trading market for the common stock of UE, AIC and Genco. Ameren holds all outstanding common stock of UE and AIC; Resources Company holds all outstanding common stock of Genco.

The following table sets forth the quarterly common stock dividend payments made by Ameren and its subsidiaries during 2010 and 2009:


(In millions)	2010 Quarter Ended								2009 Quarter Ended
Registrant	December 31		September 30		June 30		March 31		December 31		September 30		June 30		March 31
UE	$	59	$	60	$	58	$	58	$	5	$	71	$	47	$	52
AIC		33		33		34		33		86		12		-		-
Genco		-		-		-		-		-		-		20		23
Nonregistrants		-		-		-		-		-		-		15		7
Ameren	$	92	$	93	$	92	$	91	$	91	$	83	$	82	$	82

On February 9, 2011, 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, 2011, to stockholders of record on March 9, 2011.

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.

Purchase of Equity Securities

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


Period	(a) Total Number of Shares (or Units) Purchased^(a)		(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased As Part of Publicly Announced Plans or Programs		(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) That May Yet Be Purchased Under the Plans or Programs
October 1 – October 31, 2010		948	$	29.23		-		-
November 1 – November 30, 2010		-		-		-		-
December 1 – December 31, 2010		-		-		-		-
Total		948	$	29.23		-		-

(a)

The shares of Ameren common stock were purchased by Ameren in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligation to distribute shares of common stock for vested performance units. Ameren does not have any publicly announced equity securities repurchase plans or programs.

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


Period	(a) Total Number of Shares (or Units) Purchased^(a)		(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased As Part of Publicly Announced Plans or Programs		(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) That May Yet Be Purchased Under the Plans or Programs
October 1 – October 31, 2010		-	$	-		-		-
November 1 – November 30, 2010		68		73.66		-		-
December 1 – December 31, 2010		-		-		-		-
Total		68	$	73.66		-		-

(a)	The shares of CIPS preferred stock were purchased by AIC as a result of CIPS’ preferred stockholders exercising their dissenters’ rights under Illinois law.

UE and Genco did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from October 1, 2010 to December 31, 2010.

Performance Graph

The following graph shows Ameren’s cumulative total shareholder return during the five years ended December 31, 2010. 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, 2005, in Ameren common stock and in each of the indices shown, and it assumes that all of the dividends were reinvested.

LOGO


December 31,	2005		2006		2007		2008		2009		2010
Ameren	$	100	$	110.11	$	116.65	$	76.30	$	68.13	$	72.80
S&P 500 Index		100		115.79		122.15		76.95		97.31		111.97
EEI Index		100		120.76		140.76		104.30		115.47		123.60

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)	2010			2009		2008		2007		2006
Ameren:
Operating revenues^(a)	$	7,638		$	7,135	$	7,869	$	7,562	$	6,895
Operating income^(a)^(b)		916			1,416		1,362		1,359		1,188
Net income attributable to Ameren Corporation^(a)		139			612		605		618		547
Common stock dividends		368			338		534		527		522
Earnings per share – basic and diluted^(a)		0.58			2.78		2.88		2.98		2.66
Common stock dividends per share		1.54			1.54		2.54		2.54		2.54
As of December 31:
Total assets	$	23,515		$	23,702	$	22,671	$	20,752	$	19,662
Long-term debt, excluding current maturities		6,853			7,111		6,554		5,689		5,285
Preferred stock subject to mandatory redemption		-			-		-		16		17
Total Ameren Corporation stockholders’ equity		7,730			7,856		6,963		6,752		6,583
UE:
Operating revenues	$	3,197		$	2,874	$	2,960	$	2,961	$	2,823
Operating income		711			566		514		590		620
Net income available to common stockholder		364			259		245		336		343
Dividends to parent		235			175		264		267		249
As of December 31:
Total assets	$	12,504		$	12,219	$	11,529	$	10,903	$	10,290
Long-term debt, excluding current maturities		3,949			4,018		3,673		3,208		2,934
Total stockholders’ equity		4,153			4,057		3,562		3,601		3,153
AIC:
Operating revenues	$	3,014		$	2,984	$	3,508	$	3,380	$	3,353
Operating income		498			363		191		195		272
Income from continuing operations		212			133		41		56		124
Net income available to common stockholder		248			241		87		114		137
Dividends to parent		133			98		60		101		115
As of December 31:
Total assets^(c)	$	7,406		$	8,298	$	8,023	$	7,101	$	6,778
Long-term debt, excluding current maturities		1,657			1,847		1,850		1,618		1,368
Preferred stock subject to mandatory redemption		-			-		-		16		17
Total stockholders’ equity		2,576			3,072		2,655		2,635		2,612
Genco:
Operating revenues	$	1,126		$	1,148	$	1,422	$	1,298	$	1,359
Operating income^(b)		62			324		551		468		346
Net income (loss) attributable to Ameren Energy Generating Company		(39	)		160		286		230		150
Dividends to parent		-			43		221		199		223
As of December 31:
Total assets	$	2,611		$	2,920	$	2,592	$	2,288	$	2,150
Long-term debt, excluding current maturities		824			823		774		474		474
Subordinated intercompany notes (current)		-			176		145		172		206
Total Ameren Energy Generating Company stockholder’s equity		998			1,004		868		857		740

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

(b)	Includes goodwill and other asset impairment pretax charges of $589 million and $170 million recorded at Ameren and Genco, respectively, during the year ended December 31, 2010.

(c)	Includes total assets from discontinued operations of $1,117 million, $1,081 million, $865 million, and $635 million at December 31, 2009, 2008, 2007, and 2006, respectively.

ITEM 7.

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

OVERVIEW

Ameren Executive Summary

Operations

During 2010, disciplined cost management, strong customer sales and rate relief allowed Ameren to overcome the financial impact of weak wholesale power prices and higher fuel and related transportation costs. Ameren also returned its newly rebuilt Taum Sauk pumped-storage hydroelectric facility to service; installed major environmental controls at two coal-fired plants; simplified its corporate structure by merging its Illinois delivery utilities into a single company and by moving AERG under Resources Company, where Ameren’s other Merchant Generation assets reside; launched plans for growing its transmission business; and improved its safety and customer satisfaction performance.

In 2010, UE and AIC were authorized to increase rates. UE obtained approval from the MoPSC in May 2010 to increase electric rates by $230 million annually and then in February 2011 to increase natural gas rates by $9 million annually. These rate increases have been necessary to recover the cost of infrastructure investments, higher fuel costs, and other operating expenses. In November 2010, AIC received an order on rehearing from the ICC on issues arising from the ICC’s amended order of May 2010. The rehearing order authorized an additional $25 million annual rate increase, bringing the total annual revenue increase to $40 million.

Ongoing litigation exists surrounding appeals of certain aspects of UE’s two most recent electric rate orders. In February 2011, the Missouri Office of Public Counsel (MoOPC) made a filing with the MoPSC in which the MoOPC argued that a December 20, 2010 stay, granted by the Circuit Court of Cole County, Missouri (Circuit Court), of UE’s 2010 electric rate increase, as it applies to four industrial customers, should apply to all UE customers. UE disagrees with the MoOPC’s argument. On December 20, 2010, the Circuit Court found that four industrial customers appealing UE’s 2010 electric rate increase could pay the portions of their bills, representing increases from previously approved levels, into the Circuit Court’s registry pending resolution of these appeals. This effectively stayed the rate increases for those parties. UE disagrees with the Circuit Court’s ruling granting these industrial customers a stay. At this time, UE does not believe any aspect of the 2009 and 2010 electric rate increases authorized by the 2009 and 2010 Missouri electric rate orders are probable of refund to UE’s customers.

UE and AIC also have pending rate cases. In September 2010, UE filed for a $263 million annual electric rate increase. On February 8, 2011, other parties filed their initial testimony. The staff of the MoPSC recommended a rate increase of $45 million to $99 million. A key reason that the staff’s recommendation is considerably lower than

UE’s request is the staff’s use of a return on equity range of 8.25% to 9.25%, compared to UE’s request of 10.9%. While UE strongly disagrees with elements of the MoPSC’s staff and other parties’ initial recommendations, this case is still in its early stages with a decision not expected until July 2011. On February 18, 2011, AIC filed an electric and natural gas delivery rate case with the ICC requesting a $111 million aggregate increase in annual revenues. This request is based on a future test year ending December 31, 2012, with an ICC decision expected in January 2012. The use of a future test year is designed to better match AIC’s 2012 rate levels to its expected 2012 costs, reducing regulatory lag and providing an improved opportunity to earn a fair return on investment. In addition to these regulatory developments in Ameren’s state jurisdictions, Ameren is awaiting action from FERC on its August 2010 filing for pre-approval of supportive rate treatment for its proposed Grand Rivers regional electric transmission projects.

2011 could be a pivotal year in environmental regulation. The EPA is scheduled to finalize its proposed CATR, which is aimed at reducing emissions of SO₂ and NO_x. Further, the EPA is scheduled to propose requirements for retrofitting power plants with MACT to reduce hazardous air pollutants such as mercury and acid gases, cooling water standards, and rules for reducing greenhouse gas emissions. These rules are expected to impose additional costs that could be substantial to Ameren and, therefore, its customers. Ameren is continually evaluating these changing environmental standards for their impact on its power plants and is focused on meeting these requirements in the most cost effective manner possible.

Ameren remains focused on earning fair returns on investments at its rate-regulated utilities by seeking consistent, constructive regulatory outcomes, including mechanisms that reduce regulatory lag, like the use of a future test year in AIC’s pending electric and natural gas rate case filing. Further, Ameren continues to focus on disciplined cost management, including aligning its spending with the level of rates authorized by its regulators. In 2010, Ameren’s rate-regulated utilities narrowed the gap between their core earnings and their allowed returns on equity by almost three percent and by more than one percent on a weather-normalized basis. The projected 2011 return levels are expected to be below what is currently authorized and what Ameren considers appropriate. Ameren believes its pending rate cases, cost control efforts and its ongoing work to improve its regulatory frameworks will allow its rate-regulated utilities to further narrow the gap between earned and allowed returns.

Ameren’s Merchant Generation business continues to aggressively manage operating and capital costs so that this business remains stable during this period of low power prices and well-positioned to benefit from an eventual expected power price recovery. In 2010, Ameren’s Merchant Generation business further lowered its cost structure to enhance its long-term competitiveness.

Earnings

Ameren reported net income of $139 million, or 58 cents per share, for 2010 compared with net income of $612 million, or $2.78 per share, in 2009. The main factor contributing to the decline in earnings in 2010 compared with 2009 was noncash goodwill and other asset impairment charges of $522 million, or $2.19 per share, recorded in 2010 related to Ameren’s Merchant Generation business. These charges reflected a decline in the value of Ameren’s Merchant Generation business, principally as a result of sustained lower power prices and the potential enactment of more stringent environmental regulations. Ameren’s earnings were also lower in 2010, compared with 2009, because of reduced Merchant Generation margins, as a result of lower realized power prices and higher fuel and related transportation costs, and higher depreciation and amortization expense. Offsetting factors included higher electricity sales, which benefited from warmer summer weather, new utility rates in Missouri and Illinois, lower financing costs, and disciplined cost management.

Liquidity

Cash flows from operations of $1.8 billion were used to pay dividends to common stockholders of $368 million and to fund capital expenditures of $1.0 billion. At December 31, 2010, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under its existing credit facilities, of approximately $1.9 billion, which was equivalent to the amount of available liquidity at December 31, 2009.

Capital Spending

Capital expenditures decreased $673 million in 2010 compared with 2009. The reduction was a result of fewer planned expenditures for the distribution system and power plant improvements, less expenditures required to repair severe storm damage, and the completion of power plant scrubber projects in the Merchant Generation business during 2009 and early 2010.

From 2011 through 2015, cumulative capital spending is projected to range between $6.4 billion and $8.2 billion. Much of this spending is at Ameren’s rate-regulated utilities, including $265 million at ATX to expand its electric transmission assets. This five-year plan also includes significant investments in environmental projects, including the cost of installing scrubbers for two units of Genco’s Newton plant and for two units of a UE plant.

stringency of the existing ozone ambient air quality standard; the CATR, which would require further reduction of SO₂ and NO_x emissions from power plants; and a regulation governing coal ash impoundments. Within the next year, the EPA is also expected to propose new regulations under the Clean Water Act, that could require significant capital expenditures such as new water intake structures or cooling towers at our power plants; NSPS and emission guidelines for greenhouse gas emissions applicable to new and existing electric generating units; and a MACT standard for the control of hazardous air pollutants, such as mercury and acid gases from power plants. Such new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures over the next five to eight years for Ameren, UE and Genco.

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission, and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. See Note 1 – Summary of Significant Accounting Policies 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.

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

Genco operates a merchant electric generation business in Illinois and Missouri. Genco has an 80% ownership interest in EEI.

On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the AIC Merger, pursuant to the terms of the agreement, dated as of April 13, 2010. Upon consummation of the AIC Merger, the separate legal existence of CILCO and IP terminated. The second step of the reorganization involved the distribution of AERG stock from AIC to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. The AIC Merger and the distribution of AERG stock were accounted for as

transactions between entities under common control. In accordance with authoritative accounting guidance, assets and liabilities transferred between entities under common control were accounted for at the historical cost basis of the common parent, Ameren, as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren’s historical cost basis in AIC included purchase accounting adjustments related to Ameren’s acquisition of CILCORP in 2003. AIC accounted for the AERG distribution as a spinoff. AIC transferred AERG to Ameren based on AERG’s carrying value. AIC determined that the operating results of AERG qualified for discontinued operations presentation; therefore, AIC has segregated AERG’s operating results and presented them separately as discontinued operations for all periods prior to October 1, 2010, in this report. For Ameren’s financial statements, AERG’s results of operations remained classified as continuing operations. See Note 16 – Corporate Reorganization and Discontinued Operations under Part II, Item 8, for additional information.

Ameren has various other subsidiaries responsible for the marketing of power, management of commodity risks, and provision of other shared services. Ameren has an 80% ownership interest in EEI, which until February 29, 2008, was held 40% by UE and 40% by Development Company. UE reported EEI under the equity method until February 29, 2008. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren. Effective January 1, 2010, as part of an internal reorganization, Resources Company transferred its 80% stock ownership interest in EEI to Genco through a capital contribution. The transfer of EEI to Genco was accounted for as a transaction between entities under common control, whereby Genco accounted for the transfer at the historical carrying value of the parent (Ameren) as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren’s historical cost basis in EEI included purchase accounting adjustments relating to Ameren’s acquisition of an additional 20% ownership interest in EEI in 2004. This transfer required Genco’s prior-period financial statements to be retrospectively combined for all periods presented. Consequently, Genco’s prior-period consolidated financial statements reflect EEI as if it had been a subsidiary of Genco. Ameren and Genco consolidate EEI for financial reporting purposes. See Note 14 – Related Party Transactions under Part II, Item 8, for additional information.

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.

RESULTS OF OPERATIONS

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. Merchant 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 have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery service businesses, purchased power cost recovery mechanisms for our Illinois electric delivery service businesses, and a FAC for our Missouri electric utility business. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, for a discussion of pending rate cases in Missouri and Illinois. 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 and the level of purchased power costs, operations and maintenance costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.

Earnings Summary

Net income attributable to Ameren Corporation was $139 million, or $0.58 per share, for 2010, $612 million, or $2.78 per share, for 2009, and $605 million, or $2.88 per share, for 2008.

2010 versus 2009

Net income attributable to Ameren Corporation decreased $473 million and its earnings per share decreased $2.20 in 2010 compared with 2009. Net income attributable to Ameren Corporation increased in the Ameren Missouri and Ameren Illinois segments by $105 million and $81 million, respectively, in 2010 compared with 2009, while net income attributable to Ameren Corporation in the Merchant Generation segment decreased by $656 million in 2010 compared with 2009.

Compared with 2009 earnings per share, 2010 earnings were negatively affected by:

the 2010 impairment of goodwill, intangible assets, and long-lived assets within the Merchant Generation segment due to the sustained decline in market prices for electricity, industry market multiples becoming observable at lower levels than previously estimated, and potentially more stringent environmental regulations ($2.19 per share);

lower realized electric margins in the Merchant Generation segment largely due to lower realized revenue per megawatthour sold and higher fuel and related transportation costs (79 cents per share). This amount excludes the unfavorable impacts of net unrealized MTM activity on nonqualifying power hedges discussed below. See Outlook for expected trends in future coal, transportation and power prices;

higher dilution (23 cents per share) caused by an increase in the average number of common shares outstanding, largely because of a September 2009 common stock issuance, the proceeds of which were used to make investments in Ameren’s rate-regulated utilities. The impact of dilution was offset by higher earned returns on investments at Ameren’s rate-regulated utilities and lower financing costs;

costs associated with the Callaway nuclear plant’s scheduled refueling and maintenance outage in 2010. There was no Callaway refueling and maintenance outage in 2009 (12 cents per share);

increased depreciation and amortization expenses, primarily due to capital additions placed in-service at the Merchant Generation segment in late 2009 and early 2010, excluding the impacts at UE of the May 2010 MoPSC electric rate order discussed below (9 cents per share);

a reduced gain between years from net unrealized MTM activity on nonqualifying power hedges and from changes in the market value of investments used to support Ameren’s deferred compensation plans (6 cents per share); and

the impact of a federal tax change resulting from a U.S. health care reform bill that was enacted in 2010 (6 cents per share).

Compared with 2009 earnings per share, 2010 earnings were favorably affected by:

the impact of weather conditions on energy demand (estimated at 40 cents per share);

higher UE electric rates pursuant to the MoPSC 2009 and 2010 electric rate orders effective March 1, 2009, and June 21, 2010, respectively, offset by the adoption of the life span depreciation methodology and increased regulatory asset amortization as directed by the MoPSC 2010 electric rate order (27 cents per share);

the favorable impact on electric and natural gas margins in our rate-regulated businesses from higher weather-normalized sales volumes (exclusive of higher sales to Noranda discussed below), largely due to

improved economic conditions and higher wholesale sales margins at UE because of additional customers and higher-priced wholesale sales contracts, among other things (20 cents per share);

increased UE sales to Noranda as its smelter plant gradually returned to full capacity by the end of the first quarter of 2010 after a January 2009 severe ice storm significantly reduced the plant’s capacity (11 cents per share);

a reduction in financing expenses caused primarily by an increase in the allowance for funds used during construction at UE for the installation of two scrubbers at its Sioux plant (10 cents per share);

higher AIC electric and natural gas net delivery rates pursuant to the ICC 2010 rate orders, which became effective in May and November 2010 (9 cents per share); and

reduced charges in 2010 relating to workforce reductions through voluntary and involuntary separation programs (4 cents per share).

The cents per share information presented above is based on average shares outstanding in 2009.

2009 versus 2008

Net income attributable to Ameren Corporation increased $7 million and its earnings per share decreased 10 cents in 2009 compared with 2008. Net income attributable to Ameren Corporation increased in the Ameren Illinois and Ameren Missouri segments by $92 million and $25 million, respectively, in 2009 compared with 2008, while net income attributable to Ameren Corporation in the Merchant Generation segment decreased by $105 million in 2009 compared with 2008.

Compared with 2008 earnings per share, 2009 earnings were negatively affected by:

higher dilution and financing costs caused by an increase in the average number of common shares outstanding, largely because of a September 2009 common stock issuance (31 cents per share);

the impact on electric and natural gas margins in our rate-regulated businesses of higher net fuel costs at UE resulting from higher coal and related transportation costs, and lower sales prices for excess power, and lower demand (exclusive of weather impacts), among other things (30 cents per share);

the absence in 2009 of the benefit of a settlement agreement reached with a coal mine owner that reimbursed Genco, in the form of a lump-sum payment, for increased costs for coal and transportation incurred in 2008 and 2009 due to the premature closure of an Illinois mine and contract termination (18 cents per share);

the impact of milder weather conditions on energy demand (estimated at 15 cents per share);

increased depreciation and amortization expenses primarily because of capital additions at UE and at the Merchant Generation segment and additional

amortization of UE’s regulatory assets as a result of the MoPSC’s January 2009 electric rate order (12 cents per share);

reduced sales to Noranda after a January 2009 severe ice storm significantly reduced its smelter plant’s capacity (11 cents per share);

the absence in 2009 of a MoPSC rate order establishing two separate regulatory assets for previously incurred storm and MISO related costs (11 cents per share);

increased expense related to workforce reductions through voluntary and involuntary separation programs and long-lived asset impairment charges recorded primarily at Genco in 2009 (7 cents per share);

increased taxes other than income taxes, primarily because of higher property taxes (6 cents per share);

lower realized electric margins in the Merchant Generation segment largely due to lower sales volumes and higher fuel and related transportation costs (5 cents per share); and

increased distribution system reliability expenditures (5 cents per share).

Compared with 2008 earnings per share, 2009 earnings were favorably affected by:

higher AIC electric and natural gas delivery rates pursuant to an ICC rate order, which became effective on October 1, 2008 (40 cents per share);

higher UE electric rates pursuant to a MoPSC rate order, which became effective on March 1, 2009 (40 cents per share);

favorable net unrealized MTM activity on derivatives and from changes in the market value of investments used to support Ameren’s deferred compensation plans (21 cents per share);

decreased plant operations and maintenance expense because less work was undertaken as a result of cost-containment initiatives in response to weak economic conditions (15 cents per share);

the absence in 2009 of a Callaway nuclear plant refueling and maintenance outage (9 cents per share);

the absence in 2009 of asset impairment charges recorded to adjust the carrying value of AERG’s Indian Trails and Sterling Avenue generating facilities to their estimated fair values as of December 31, 2008 (6 cents per share); and

the reduced impact in 2009 of the electric rate relief and customer assistance programs provided to certain AIC electric customers under the 2007 Illinois Electric Settlement Agreement (5 cents per share).

The cents per share information presented above is based on average shares outstanding in 2008.

For additional details regarding the Ameren Companies’ results of operations, including explanations of Margins, Other Operations and Maintenance Expenses, Goodwill and Other Impairment Losses, Depreciation and Amortization, Taxes Other Than Income Taxes, Interest Charges, and Income Taxes, see the major headings below.

Because it is a holding company, Ameren’s net income and cash flows are primarily generated by its principal subsidiaries: UE, AIC and Genco. The following table presents the contribution by Ameren’s principal subsidiaries to Ameren’s consolidated net income for the years ended December 31, 2010, 2009 and 2008:


	2010			2009			2008
Net income (loss):
UE^(a)	$	364		$	259		$	245
AIC^(b)		248			241			87
Genco		(39	)		160			286
Other^(c⁾		(434	)		(48	)		(13	)
Net income attributable to Ameren Corporation	$	139		$	612		$	605

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

(b)	Includes AERG for all periods prior to October 1, 2010, when AIC distributed AERG stock to Ameren.

(c)

Includes earnings from other merchant generation operations, as well as corporate general and administrative expenses, and intercompany eliminations. During 2010, Ameren Corporation, parent, and other nonregistrant subsidiaries recorded a $419 million impairment charge related to goodwill, long-lived assets, and intangible assets in the Merchant Generation segment.

Below is a table of income statement components by segment for the years ended December 31, 2010, 2009, and 2008:


2010	Ameren Missouri			Ameren Illinois			Merchant Generation			Other / Intersegment Eliminations			Total
Electric margins	$	2,233		$	1,096		$	780		$	(17	)	$	4,092
Natural gas margins		75			375			-			(2	)		448
Other revenues		1			-			-			(1	)		-
Other operations and maintenance		(931	)		(635	)		(287	)		32			(1,821	)
Goodwill and other impairment losses		-			-			(589	)		-			(589	)
Depreciation and amortization		(382	)		(210	)		(146	)		(27	)		(765	)
Taxes other than income taxes		(285	)		(128	)		(26	)		(10	)		(449	)
Other income and (expenses)		70			(6	)		1			(8	)		57
Interest charges		(213	)		(143	)		(133	)		(8	)		(497	)
Income (taxes) benefit		(199	)		(137	)		(6	)		17			(325	)
Net income (loss)		369			212			(406	)		(24	)		151
Noncontrolling interest and preferred dividends		(5	)		(4	)		(3	)		-			(12	)
Net income (loss) attributable to Ameren Corporation	$	364		$	208		$	(409	)	$	(24	)	$	139
2009
Electric margins	$	1,983		$	917		$	1,012		$	(22	)	$	3,890
Natural gas margins		73			373			-			-			446
Other revenues		4			4			-			(8	)		-
Other operations and maintenance		(880	)		(590	)		(333	)		35			(1,768	)
Goodwill and other impairment losses		-			-			(7	)		-			(7	)
Depreciation and amortization		(357	)		(216	)		(126	)		(26	)		(725	)
Taxes other than income taxes		(257	)		(125	)		(28	)		(10	)		(420	)
Other income and (expenses)		56			2			1			(11	)		48
Interest charges		(229	)		(153	)		(119	)		(7	)		(508	)
Income (taxes) benefit		(128	)		(79	)		(151	)		26			(332	)
Net income (loss)		265			133			249			(23	)		624
Noncontrolling interest and preferred dividends		(6	)		(6	)		(2	)		2			(12	)
Net income (loss) attributable to Ameren Corporation	$	259		$	127		$	247		$	(21	)	$	612
2008
Electric margins	$	1,924		$	837		$	1,188		$	(47	)	$	3,902
Natural gas margins		78			351			-			(4	)		425
Other revenues		3			1			-			(4	)		-
Other operations and maintenance		(922	)		(653	)		(342	)		55			(1,862	)
Goodwill and other impairment losses		-			-			(14	)		-			(14	)
Depreciation and amortization		(329	)		(219	)		(109	)		(28	)		(685	)
Taxes other than income taxes		(240	)		(126	)		(26	)		(12	)		(404	)
Other income and (expenses)		53			11			-			(15	)		49
Interest charges		(193	)		(145	)		(99	)		(3	)		(440	)
Income (taxes) benefit		(134	)		(16	)		(217	)		40			(327	)
Net income (loss)		240			41			381			(18	)		644
Noncontrolling interest and preferred dividends		(6	)		(6	)		(29	)		2			(39	)
Net income (loss) attributable to Ameren Corporation	$	234		$	35		$	352		$	(16	)	$	605

Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and natural gas margins from the previous year. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as gas revenues less gas purchased for resale. The table covers the years ended December 31, 2010, 2009, and 2008. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural 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.


2010 versus 2009	Ameren^(a)			UE			AIC			Genco
Electric revenue change:
Effect of weather (estimate)^(b)	$	174		$	134		$	40		$	-
Regulated rates:
Changes in base rates		203			162			41			-
Noranda sales		54			54			-			-
Illinois pass-through power supply costs		220			-			(83	)		-
Energy efficiency programs and environmental remediation cost riders		29			-			29			-
Bad debt rider		14			-			14			-
Transmission services		49			7			42			-
Recovery of FAC net under-recovery		60			60			-			-
Sales price changes, including hedge effect		(243	)		-			-			(81	)
Off-system revenues		(102	)		(102	)		-			-
2007 Illinois Electric Settlement Agreement, net of reimbursement		23			-			10			10
Net unrealized MTM gains (losses)		49			-			-			(1	)
Sales (excluding impact of abnormal weather) and other		51			15			3			50
Total electric revenue change	$	581		$	330		$	96		$	(22	)
Fuel and purchased power change:
Fuel:
Production volume and other	$	(138	)	$	(91	)	$	-		$	(38	)
FAC net under-recovery		138			138			-			-
Recovery of FAC net under-recovery		(60	)		(60	)		-			-
Net unrealized MTM losses		(51	)		(29	)		-			(18	)
Price – Merchant Generation		(71	)		-			-			(51	)
Purchased power		23			(38	)		-			11
Illinois pass-through power supply costs		(220	)		-			83			-
Total fuel and purchased power change	$	(379	)	$	(80	)	$	83		$	(96	)
Net change in electric margins	$	202		$	250		$	179		$	(118	)
Natural gas margins change:
Effect of weather (estimate)^(b)	$	1		$	-		$	1		$	-
Bad debt rider		15			-			15			-
Rate decrease		(11	)		-			(11	)		-
Energy efficiency programs and environmental remediation cost riders		1			-			1			-
Net unrealized MTM losses		(6	)		-			(6	)		-
Sales (excluding impact of abnormal weather) and other		2			2			2			-
Net change in natural gas margins	$	2		$	2		$	2		$	-


2009 versus 2008	Ameren^(a)			UE			AIC			Genco
Electric revenue change:
Effect of weather (estimate)^(b)	$	(47	)	$	(33	)	$	(14	)	$	-
Regulated rates:
Changes in base rates		229			141			88			-
Noranda sales		(50	)		(50	)		-			-
Illinois pass-through power supply costs		(338	)		-			(338	)		-
Energy efficiency programs and environmental remediation cost riders		11			-			11			-
Sales price changes, including hedge effect		57			-			-			(48	)
Off-system revenues		(89	)		(89	)		-			-
2007 Illinois Electric Settlement Agreement		15			-			5			7
Net unrealized MTM (losses) gains		(110	)		-			-			2
Sales (excluding impact of abnormal weather) and other		(125	)		(25	)		(29	)		(235	)
Total electric revenue change	$	(447	)	$	(56	)	$	(277	)	$	(274	)
Fuel and purchased power change:
Fuel:
Production volume and other	$	88		$	(17	)	$	1		$	93
FAC net under-recovery, net of collections		38			38			-			-
Net unrealized MTM gains		118			58			-			48
Price – Merchant Generation		(83	)		-			-			(80	)
Coal contract settlement		(27	)		-			-			(27	)
Purchased power		(25	)		48			18			25
Illinois pass-through power supply costs		338			-			338			-
FERC-ordered MISO resettlements		(12	)		(12	)		-			-
Total fuel and purchased power change	$	435		$	115		$	357		$	59
Net change in electric margins	$	(12	)	$	59		$	80		$	(215	)
Natural gas margins change:
Effect of weather (estimate)^(b)	$	(7	)	$	(1	)	$	(6	)	$	-
Changes in base rates		34			-			34			-
Absence of capitalization of nonrecoverable gas costs