10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the Quarterly Period Ended March 31, 2011

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

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

Ameren Corporation	Yes	x	No	¨
Union Electric Company	Yes	x	No	¨
Ameren Illinois Company	Yes	x	No	¨
Ameren Energy Generating Company	Yes	x	No	¨

Indicate by check mark whether each registrant has submitted electronically and posted on its corporate Web site, 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	x	No	¨
Union Electric Company	Yes	¨	No	¨
Ameren Illinois Company	Yes	¨	No	¨
Ameren Energy Generating Company	Yes	¨	No	¨

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

	Large Accelerated Filer	Accelerated Filer	Non-Accelerated Filer	Smaller Reporting Company
Ameren Corporation	x	¨	¨	¨
Union Electric Company	¨	¨	x	¨
Ameren Illinois Company	¨	¨	x	¨
Ameren Energy Generating Company	¨	¨	x	¨

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

Ameren Corporation	Yes	¨	No	x
Union Electric Company	Yes	¨	No	x
Ameren Illinois Company	Yes	¨	No	x
Ameren Energy Generating Company	Yes	¨	No	x

The number of shares outstanding of each registrant’s classes of common stock as of April 29, 2011, was as follows:

Ameren Corporation	Common stock, $0.01 par value per share - 241,148,657
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

OMISSION OF CERTAIN INFORMATION

Ameren Energy Generating Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

This combined Form 10-Q 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 quarterly 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			3
Forward-looking Statements			3
PART I	Financial Information
Item 1.	Financial Statements (Unaudited)
	Ameren Corporation
	Consolidated Statement of Income		5
	Consolidated Balance Sheet		6
	Consolidated Statement of Cash Flows		7
	Union Electric Company
	Statement of Income		8
	Balance Sheet		9
	Statement of Cash Flows		10
	Ameren Illinois Company
	Consolidated Statement of Income		11
	Balance Sheet		12
	Consolidated Statement of Cash Flows		13
	Ameren Energy Generating Company
	Consolidated Statement of Income		14
	Consolidated Balance Sheet		15
	Consolidated Statement of Cash Flows		16
	Combined Notes to Financial Statements		17
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		51
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		74
Item 4.	Controls and Procedures		79
PART II	Other Information
Item 1.	Legal Proceedings		79
Item 1A.	Risk Factors		79
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		80
Item 6.	Exhibits		81
Signatures			83

This Form 10-Q contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors included on page 4 of this Form 10-Q 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.

2

GLOSSARY OF TERMS AND ABBREVIATIONS

We use the words “our,” “we” or “us” with respect to certain information that relates to the individual registrants within the Ameren Corporation consolidated group. When appropriate, subsidiaries of Ameren Corporation are named specifically as their various business activities are discussed. Refer to the 2010 Form 10-K for a complete listing of glossary terms and abbreviations. Only new or significantly changed terms and abbreviations are included below.

Ameren Missouri or AMO - 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. Ameren Missouri is also defined as a financial reporting segment consisting of Union Electric Company’s rate-regulated businesses.

CCR - Coal combustion residuals.

Cole County Circuit Court - Circuit Court of Cole County, Missouri.

Form 10-K - The combined Annual Report on Form 10-K for the year ended December 31, 2010, filed by the Ameren Companies with the SEC.

MIEC - Missouri Industrial Energy Consumers.

MoOPC - Missouri Office of Public Counsel.

NO₂ - Nitrogen dioxide.

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 in the Form 10-K 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 Ameren Missouri electric rate proceeding and the AIC electric and natural gas rate proceedings; the court appeals related to Ameren Missouri’s 2009 and 2010 electric rate orders and the court appeals related to AIC’s 2010 electric and natural gas rate order; the MoPSC’s FAC prudence review and future appeals; 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 Ameren Missouri 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 through our regulatory frameworks;

• the effects of our and other members' participation in, or potential withdrawal from, MISO, and the effects of new members joining 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;

3

• 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 Ameren Missouri prevails in its claims against insurers in connection with its Taum Sauk pumped-storage hydroelectric plant incident;

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

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

• operation of Ameren Missouri’s nuclear power facility, including planned and unplanned outages, decommissioning costs and potential increased costs as a result of recent nuclear-related developments in Japan;

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

• the completion of Genco’s sale of its Columbia CT facility to the city of Columbia, Missouri;

• 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.

4

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions, except per share amounts)

	Three Months Ended March 31,
	2011		2010
Operating Revenues:
Electric	$	1,470	$	1,455
Gas		434		485
Total operating revenues		1,904		1,940
Operating Expenses:
Fuel		379		293
Purchased power		227		271
Gas purchased for resale		288		333
Other operations and maintenance		463		437
Depreciation and amortization		195		187
Taxes other than income taxes		125		121
Total operating expenses		1,677		1,642
Operating Income		227		298
Other Income and Expenses:
Miscellaneous income		16		22
Miscellaneous expense		5		7
Total other income		11		15
Interest Charges		119		132
Income Before Income Taxes		119		181
Income Taxes		45		75
Net Income		74		106
Less: Net Income Attributable to Noncontrolling Interests		3		4
Net Income Attributable to Ameren Corporation	$	71	$	102
Earnings per Common Share – Basic and Diluted	$	0.29	$	0.43
Dividends per Common Share	$	0.385	$	0.385
Average Common Shares Outstanding		240.6		237.6

The accompanying notes are an integral part of these consolidated financial statements.

5

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions, except per share amounts)

		December 31,		December 31,
	March 31, 2011		December 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	573	$	545
Accounts receivable – trade (less allowance for doubtful accounts of $33 and $23, respectively)		517		500
Unbilled revenue		310		406
Miscellaneous accounts and notes receivable		291		231
Materials and supplies		572		707
Mark-to-market derivative assets		137		129
Current regulatory assets		215		267
Other current assets		100		109
Total current assets		2,715		2,894
Property and Plant, Net		17,888		17,853
Investments and Other Assets:
Nuclear decommissioning trust fund		353		337
Goodwill		411		411
Intangible assets		7		7
Regulatory assets		1,217		1,263
Other assets		738		750
Total investments and other assets		2,726		2,768
TOTAL ASSETS	$	23,329	$	23,515
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	155	$	155
Short-term debt		334		269
Accounts and wages payable		401		651
Taxes accrued		134		63
Interest accrued		153		107
Customer deposits		100		100
Mark-to-market derivative liabilities		126		161
Current regulatory liabilities		140		99
Other current liabilities		294		283
Total current liabilities		1,837		1,888
Credit Facility Borrowings		270		460
Long-term Debt, Net		6,853		6,853
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		2,938		2,886
Accumulated deferred investment tax credits		88		90
Regulatory liabilities		1,371		1,319
Asset retirement obligations		482		475
Pension and other postretirement benefits		1,057		1,045
Other deferred credits and liabilities		553		615
Total deferred credits and other liabilities		6,489		6,430
Commitments and Contingencies (Notes 2, 8, 9 and 10)
Ameren Corporation Stockholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 241.1 and 240.4, respectively		2		2
Other paid-in capital, principally premium on common stock		5,540		5,520
Retained earnings		2,203		2,225
Accumulated other comprehensive loss		(20)		(17)
Total Ameren Corporation stockholders’ equity		7,725		7,730
Noncontrolling Interests		155		154
Total equity		7,880		7,884
TOTAL LIABILITIES AND EQUITY	$	23,329	$	23,515

The accompanying notes are an integral part of these consolidated financial statements.

6

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Three Months Ended March 31,
	2011		2010
Cash Flows From Operating Activities:
Net income	$	74	$	106
Adjustments to reconcile net income to net cash provided by operating activities:
Net mark-to-market gain on derivatives		(16)		(31)
Depreciation and amortization		196		190
Amortization of nuclear fuel		17		13
Amortization of debt issuance costs and premium/discounts		5		9
Deferred income taxes and investment tax credits, net		62		70
Other		(3)		(8)
Changes in assets and liabilities:
Receivables		17		40
Materials and supplies		135		148
Accounts and wages payable		(221)		(181)
Taxes accrued		71		40
Assets, other		39		(32)
Liabilities, other		80		9
Pension and other postretirement benefits		28		30
Counterparty collateral, net		70		(23)
Net cash provided by operating activities		554		380
Cash Flows From Investing Activities:
Capital expenditures		(227)		(289)
Nuclear fuel expenditures		(18)		(23)
Purchases of securities – nuclear decommissioning trust fund		(91)		(60)
Sales of securities – nuclear decommissioning trust fund		87		56
Other		(1)		(1)
Net cash used in investing activities		(250)		(317)
Cash Flows From Financing Activities:
Dividends on common stock		(93)		(91)
Dividends paid to noncontrolling interest holders		(2)		(2)
Short-term and credit facility borrowings, net		(125)		(220)
Issuances of common stock		17		20
Generator advances for construction refunded, net of receipts		(73)		(32)
Net cash used in financing activities		(276)		(325)
Net change in cash and cash equivalents		28		(262)
Cash and cash equivalents at beginning of year		545		622
Cash and cash equivalents at end of period	$	573	$	360

The accompanying notes are an integral part of these consolidated financial statements.

7

UNION ELECTRIC COMPANY

STATEMENT OF INCOME

(Unaudited) (In millions)

	Three Months Ended March 31,
	2011		2010
Operating Revenues:
Electric	$	702	$	607
Gas		69		75
Other		1		-
Total operating revenues		772		682
Operating Expenses:
Fuel		229		124
Purchased power		20		44
Gas purchased for resale		40		46
Other operations and maintenance		233		218
Depreciation and amortization		100		92
Taxes other than income taxes		73		68
Total operating expenses		695		592
Operating Income		77		90
Other Income and Expenses:
Miscellaneous income		13		21
Miscellaneous expense		3		2
Total other income		10		19
Interest Charges		54		59
Income Before Income Taxes		33		50
Income Taxes		11		22
Net Income		22		28
Preferred Stock Dividends		1		1
Net Income Available to Common Stockholder	$	21	$	27

The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.

8

UNION ELECTRIC COMPANY

BALANCE SHEET

(Unaudited) (In millions, except per share amounts)

		December 31,		December 31,
	March 31, 2011		December 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	38	$	202
Accounts receivable – trade (less allowance for doubtful accounts of $11 and $8, respectively)		218		217
Accounts receivable – affiliates		3		6
Unbilled revenue		136		159
Miscellaneous accounts and notes receivable		125		116
Materials and supplies		327		341
Current regulatory assets		138		179
Other current assets		66		55
Total current assets		1,051		1,275
Property and Plant, Net		9,814		9,775
Investments and Other Assets:
Nuclear decommissioning trust fund		353		337
Intangible assets		4		2
Regulatory assets		690		694
Other assets		430		421
Total investments and other assets		1,477		1,454
TOTAL ASSETS	$	12,342	$	12,504
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	5	$	5
Accounts and wages payable		161		326
Accounts payable – affiliates		77		75
Taxes accrued		75		76
Interest accrued		59		63
Current regulatory liabilities		41		23
Current accumulated deferred income taxes, net		33		43
Other current liabilities		83		89
Total current liabilities		534		700
Long-term Debt, Net		3,949		3,949
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,931		1,908
Accumulated deferred investment tax credits		77		78
Regulatory liabilities		800		766
Asset retirement obligations		368		363
Pension and other postretirement benefits		376		369
Other deferred credits and liabilities		201		218
Total deferred credits and other liabilities		3,753		3,702
Commitments and Contingencies (Notes 2, 8, 9 and 10)
Stockholders’ Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding		511		511
Other paid-in capital, principally premium on common stock		1,555		1,555
Preferred stock not subject to mandatory redemption		80		80
Retained earnings		1,960		2,007
Total stockholders’ equity		4,106		4,153
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	12,342	$	12,504

The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.

9

UNION ELECTRIC COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Three Months Ended March 31,
	2011		2010
Cash Flows From Operating Activities:
Net income	$	22	$	28
Adjustments to reconcile net income to net cash provided by operating activities:
Net mark-to-market loss on derivatives		1		-
Depreciation and amortization		100		92
Amortization of nuclear fuel		17		13
Amortization of debt issuance costs and premium/discounts		2		3
Deferred income taxes and investment tax credits, net		9		34
Allowance for equity funds used during construction		(6)		(12)
Changes in assets and liabilities:
Receivables		16		(16)
Materials and supplies		14		15
Accounts and wages payable		(159)		(159)
Taxes accrued		(1)		53
Assets, other		22		(29)
Liabilities, other		14		1
Pension and other postretirement benefits		14		11
Net cash provided by operating activities		65		34
Cash Flows From Investing Activities:
Capital expenditures		(118)		(163)
Nuclear fuel expenditures		(18)		(23)
Purchases of securities – nuclear decommissioning trust fund		(91)		(60)
Sales of securities – nuclear decommissioning trust fund		87		56
Other		(1)		-
Net cash used in investing activities		(141)		(190)
Cash Flows From Financing Activities:
Dividends on common stock		(68)		(58)
Dividends on preferred stock		(1)		(1)
Generator advances for construction received (refunded)		(19)		3
Net cash used in financing activities		(88)		(56)
Net change in cash and cash equivalents		(164)		(212)
Cash and cash equivalents at beginning of year		202		267
Cash and cash equivalents at end of period	$	38	$	55

The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.

10

AMEREN ILLINOIS COMPANY

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions)

	Three Months Ended March 31,
	2011		2010(a)
Operating Revenues:
Electric	$	442	$	501
Gas		366		410
Total operating revenues		808		911
Operating Expenses:
Purchased power		211		269
Gas purchased for resale		248		286
Other operations and maintenance		168		162
Depreciation and amortization		52		54
Taxes other than income taxes		41		42
Total operating expenses		720		813
Operating Income		88		98
Other Income and Expenses:
Miscellaneous income		2		2
Miscellaneous expense		1		3
Total other income (expense)		1		(1)
Interest Charges		35		37
Income Before Income Taxes		54		60
Income Taxes		20		24
Income from Continuing Operations		34		36
Income from Discontinued Operations, net of tax		-		12
Net Income		34		48
Preferred Stock Dividends		1		1
Net Income Available to Common Stockholder	$	33	$	47

^(a) Prior period reflects the AIC Merger as discussed in Note 1 - Summary of Significant Accounting Policies.

The accompanying notes as they relate to AIC are an integral part of these consolidated financial statements.

11

AMEREN ILLINOIS COMPANY

BALANCE SHEET

(Unaudited) (In millions)

		December 31,		December 31,
	March 31, 2011		December 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	508	$	322
Accounts receivable – trade (less allowance for doubtful accounts of $21 and $13, respectively)		265		230
Accounts receivable – affiliates		14		73
Unbilled revenue		133		205
Miscellaneous accounts and notes receivable		110		44
Materials and supplies		75		198
Current regulatory assets		255		260
Other current assets		110		106
Total current assets		1,470		1,438
Property and Plant, Net		4,612		4,576
Investments and Other Assets:
Tax receivable – Genco		66		72
Goodwill		411		411
Regulatory assets		673		747
Other assets		129		162
Total investments and other assets		1,279		1,392
TOTAL ASSETS	$	7,361	$	7,406
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	150	$	150
Accounts and wages payable		134		182
Accounts payable – affiliates		92		82
Taxes accrued		72		26
Interest accrued		53		27
Customer deposits		84		83
Mark-to-market derivative liabilities		69		82
Mark-to-market derivative liabilities – affiliates		179		172
Environmental remediation		65		72
Current regulatory liabilities		99		76
Other current liabilities		54		63
Total current liabilities		1,051		1,015
Long-term Debt, Net		1,657		1,657
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		759		724
Accumulated deferred investment tax credits		8		8
Regulatory liabilities		570		553
Pension and other postretirement benefits		418		413
Other deferred credits and liabilities		353		460
Total deferred credits and other liabilities		2,108		2,158
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholders’ Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding		-		-
Other paid-in capital		1,952		1,952
Preferred stock not subject to mandatory redemption		62		62
Retained earnings		512		542
Accumulated other comprehensive income		19		20
Total stockholders’ equity		2,545		2,576
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	7,361	$	7,406

The accompanying notes as they relate to AIC are an integral part of these consolidated financial statements.

12

AMEREN ILLINOIS COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Three Months Ended March 31,
	2011		2010(a)
Cash Flows From Operating Activities:
Net income	$	34	$	48
Income from discontinued operations, net of tax		-		(12)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		52		54
Amortization of debt issuance costs and premium/discounts		2		3
Deferred income taxes and investment tax credits, net		34		(3)
Other		-		(1)
Changes in assets and liabilities:
Receivables		(17)		(2)
Materials and supplies		123		128
Accounts and wages payable		(47)		(69)
Taxes accrued		46		30
Assets, other		40		(71)
Liabilities, other		44		(17)
Pension and other postretirement benefits		11		11
Operating cash flows provided by discontinued operations		-		43
Net cash provided by operating activities		322		142
Cash Flows From Investing Activities:
Capital expenditures		(69)		(76)
Returns from (advances to) ATXI for construction		49		(3)
Net investing activities used in discontinued operations		-		(2)
Net cash used in investing activities		(20)		(81)
Cash Flows From Financing Activities:
Dividends on common stock		(62)		(33)
Dividends on preferred stock		(1)		(1)
Generator advances for construction refunded, net of receipts		(53)		(35)
Net financing activities used in discontinued operations		-		(43)
Net cash used in financing activities		(116)		(112)
Net change in cash and cash equivalents		186		(51)
Cash and cash equivalents at beginning of year		322		306
Cash and cash equivalents at end of period	$	508	$	255
Noncash investing activity – asset transfer from ATXI	$	20	$	1

^(a) Prior period reflects the AIC Merger as discussed in Note 1 - Summary of Significant Accounting Policies.

The accompanying notes as they relate to AIC are an integral part of these consolidated financial statements.

13

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions)

	Three Months Ended March 31,
	2011		2010
Operating Revenues	$	241	$	266
Operating Expenses:
Fuel		111		124
Other operations and maintenance		45		49
Depreciation and amortization		24		24
Taxes other than income taxes		7		7
Total operating expenses		187		204
Operating Income		54		62
Miscellaneous Expense		-		1
Interest Charges		17		19
Income Before Income Taxes		37		42
Income Taxes		15		18
Net Income		22		24
Less: Net Income Attributable to Noncontrolling Interest		1		1
Net Income Attributable to Ameren Energy Generating Company	$	21	$	23

The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.

14

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions)

		December 31,		December 31,
	March 31, 2011		December 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	6	$	6
Accounts receivable – affiliates		81		126
Miscellaneous accounts and notes receivable		35		19
Advances to money pool		90		25
Materials and supplies		126		130
Mark-to-market derivative assets		32		26
Other current assets		10		4
Total current assets		380		336
Property and Plant, Net		2,254		2,248
Investments and Other Assets:
Intangible assets		2		3
Other assets		26		24
TOTAL ASSETS	$	2,662	$	2,611
LIABILITIES AND EQUITY
Current Liabilities:
Accounts and wages payable	$	47	$	62
Accounts payable – affiliates		16		23
Current portion of tax payable – AIC		12		8
Taxes accrued		37		20
Interest accrued		27		13
Mark-to-market derivative liabilities		7		9
Mark-to-market derivative liabilities – affiliates		5		5
Current accumulated deferred income taxes, net		21		13
Other current liabilities		11		12
Total current liabilities		183		165
Credit Facility Borrowings		100		100
Long-term Debt, Net		824		824
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		271		253
Accumulated deferred investment tax credits		3		3
Tax payable – AIC		66		72
Asset retirement obligations		75		74
Pension and other postretirement benefits		85		88
Other deferred credits and liabilities		23		23
Total deferred credits and other liabilities		523		513
Commitments and Contingencies (Notes 8 and 9)
Ameren Energy Generating Company Stockholder’s Equity:
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding		-		-
Other paid-in capital		649		649
Retained earnings		414		393
Accumulated other comprehensive loss		(43)		(44)
Total Ameren Energy Generating Company stockholder’s equity		1,020		998
Noncontrolling Interest		12		11
Total equity		1,032		1,009
TOTAL LIABILITIES AND EQUITY	$	2,662	$	2,611

The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.

15

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Three Months Ended March  31,
	2011		2010
Cash Flows From Operating Activities:
Net income	$	22	$	24
Adjustments to reconcile net income to net cash provided by operating activities:
Net mark-to-market gain on derivatives		(15)		(1)
Depreciation and amortization		25		27
Amortization of debt issuance costs and discounts		1		1
Deferred income taxes and investment tax credits, net		26		13
Changes in assets and liabilities:
Receivables		29		35
Materials and supplies		4		2
Accounts and wages payable		(16)		(31)
Taxes accrued		17		12
Assets, other		(3)		2
Liabilities, other		12		16
Pension and other postretirement benefits		(2)		3
Net cash provided by operating activities		100		103
Cash Flows From Investing Activities:
Capital expenditures		(35)		(40)
Changes in money pool advances		(65)		(41)
Net cash used in investing activities		(100)		(81)
Cash Flows From Financing Activities:
Note payable – Ameren		-		(22)
Net cash used in financing activities		-		(22)
Net change in cash and cash equivalents		-		-
Cash and cash equivalents at beginning of year		6		6
Cash and cash equivalents at end of period	$	6	$	6

The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.

16

AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY

AMEREN ILLINOIS COMPANY (Consolidated)

AMEREN ENERGY GENERATING COMPANY (Consolidated)

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

March 31, 2011

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, 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 expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report.

• Ameren Missouri, or Union Electric Company, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.

• AIC, or Ameren Illinois Company, which does business as Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

• Genco, or Ameren Energy Generating Company, operates a merchant electric generation business in Illinois and Missouri. Genco has an 80% ownership interest in EEI.

Ameren has various other subsidiaries responsible for such activities as the marketing of power and provision of other shared services.

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. 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 has segregated AERG’s operating results and cash flows and presented them separately as discontinued operations in its consolidated statement of income and consolidated statement of cash flows, respectively, for all periods presented prior to October 1, 2010, in this report. For Ameren’s financial statements, AERG’s results of operations remain classified as continuing operations. See Note 14 - Discontinued Operations for additional information.

The financial statements of Ameren, AIC and Genco are prepared on a consolidated basis. Ameren Missouri has no subsidiaries, and therefore its financial statements were not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three months ended March 31, 2011, and 2010. The number of restricted stock shares and performance share units outstanding had an immaterial impact on earnings per share.

17

Long-term Incentive Plan of 1998 and 2006 Omnibus Incentive Compensation Plan

A summary of nonvested shares as of March 31, 2011, and changes during the three months ended March 31, 2011, under the Long-term Incentive Plan of 1998, as amended (1998 Plan), and the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

	Performance Share Units(a)					Restricted Shares(b)
	Share Units			Weighted-average Fair Value Per Unit at Grant Date		Shares			Weighted-average Fair Value Per Share at Grant Date
Nonvested at January 1, 2011		1,142,768		$	23.96		83,154		$	49.87
Granted(c)		731,962			31.41		-			-
Dividends		-			-		260			28.22
Forfeitures		(9,393	)		25.66		(560	)		50.45
Vested(d)		(122,185	)		31.00		(63,574	)		49.47
Nonvested at March 31, 2011		1,743,152		$	26.58		19,280		$	51.21

(a) Granted under the 2006 Plan.

(b) Granted under the 1998 Plan.

(c) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2011 under the 2006 Plan.

(d) Shares/units vested due to Ameren attainment of performance goals and retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period.

The fair value of each share unit awarded in January 2011 under the 2006 Plan was determined to be $31.41. That amount was based on Ameren’s closing common share price of $28.19 at December 31, 2010, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2011. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.08%, volatility of 22% to 36% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.

Ameren recorded compensation expense of $3 million and $5 million for the three months ended March 31, 2011, and 2010, respectively, and a related tax benefit of $1 million and $2 million for the three months ended March 31, 2011, and 2010, respectively. As of March 31, 2011, total compensation expense of $30 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 25 months.

Accounting Changes

See Note 7 - Fair Value Measurements for a summary of recently adopted authoritative accounting guidance relating to fair value measurements.

Goodwill and Intangible Assets

Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. As of March 31, 2011, Ameren’s and AIC’s goodwill related to the acquisition of IP in 2004 and the acquisition of CILCORP in 2003. We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events or changes in circumstances indicate that the asset might be impaired.

Intangible Assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired. Ameren’s, Ameren Missouri’s and Genco’s intangible assets at March 31, 2011, primarily consisted of emission allowances. See Note 9 - Commitments and Contingencies for additional information on emission allowances. Additionally, at March 31, 2011, Ameren’s and Ameren Missouri’s intangible assets included renewable energy credits obtained through wind and solar purchase power agreements. The book value of each of Ameren’s and Ameren Missouri’s renewable energy credits as of March 31, 2011, was $2 million.

The following table presents the SO₂ and NO_x emission allowances held and the related aggregate SO₂ and NO_x emission allowance book values that were carried as intangible assets as of March 31, 2011. Emission allowances consist of various individual emission allowance certificates and do not expire.

SO2 and NOx in tons	SO 2(a)		NO x(b)		Book Value(c)
Ameren(d)		3,260,933		71,693	$	5
AMO		1,684,072		47,892		2
Genco		1,179,536		20,008		2
Other		397,325		3,793		1

(a) Vintages are from 2011 to 2021. Each company possesses additional allowances for use in periods beyond 2021.

(b) Vintage is 2011 and the remaining unused prior years’ allowances.

(c) The book value at December 31, 2010, for Ameren, Ameren Missouri and Genco was $7 million, $2 million, and $3 million, respectively.

(d) Includes amounts for Ameren registrants and nonregistrants subsidiaries.

18

Emission allowances are charged to fuel expense as they are used in operations. The following table presents amortization expense based on usage of emission allowances for Ameren, Ameren Missouri and Genco during the three months ended March 31, 2011, and 2010:

	Three Months
	2011		2010
Ameren(a)	$	1	$	3
AMO		-		(b	)
Genco(a)		1		3

(a) Includes allowances consumed that were recorded through purchase accounting.

(b) Less than $1 million.

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and Ameren Missouri and AIC natural gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes on the statement of income. Excise taxes reflected on AIC electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes for the three months ended March 31, 2011 and 2010:

	Three Months
	2011		2010
Ameren	$	51	$	46
AMO		29		25
AIC		22		21

Uncertain Tax Positions

The amount of unrecognized tax benefits as of March 31, 2011, was $247 million, $167 million, $53 million, and $21 million for Ameren, Ameren Missouri, AIC and Genco, respectively. The amount of unrecognized tax benefits as of March 31, 2011, that would impact the effective tax rate, if recognized, was less than $1 million, $3 million, less than $1 million and $1 million for Ameren, Ameren Missouri, AIC and Genco, respectively.

Ameren’s federal income tax returns for the years 2005 through 2009 are before the Appeals Office of the Internal Revenue Service.

State income tax returns are generally subject to examination for a period of three years after filing of the return. The Ameren Companies do not currently have material state income tax issues under examination, administrative appeals, or litigation. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states.

It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe such increases or decreases would be material to their results of operations, financial position or liquidity.

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri, AIC and Genco increased compared to December 31, 2010, to reflect the accretion of obligations to their fair values.

Noncontrolling Interest

Ameren’s noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren’s subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren’s equity in its consolidated balance sheet. Genco’s noncontrolling interest comprised the 20% of EEI not owned by Genco. This noncontrolling interest was classified as a component of equity separate from Genco’s equity in its consolidated balance sheet.

A reconciliation of the equity changes attributable to the noncontrolling interest at Ameren and Genco for the three months ended March 31, 2011, and 2010, is shown below:

	Three Months
	2011			2010
Ameren:
Noncontrolling interest, beginning of period	$	154		$	204
Net income attributable to noncontrolling interest		3			4
Dividends paid to noncontrolling interest holders		(2	)		(2	)
Noncontrolling interest, end of period	$	155		$	206
Genco:
Noncontrolling interest, beginning of period	$	11		$	9
Net income attributable to noncontrolling interest		1			1
Noncontrolling interest, end of period	$	12		$	10

19

Genco Asset Sale

In April 2011, Genco reached an agreement to sell its remaining interest in the Columbia CT facility to the city of Columbia, Missouri. The sale is scheduled to be completed by June 1, 2011. Genco expects to receive cash proceeds of $45 million from the sale upon closing. Upon the completion of this sale, the existing power purchase agreements between Marketing Company and the city of Columbia would be terminated.

NOTE 2 - RATE AND REGULATORY MATTERS

Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.

Missouri

2009 Electric Rate Order

In January 2009, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues of approximately $162 million for electric service and the implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism, among other things. In February 2009, Noranda, Ameren Missouri’s largest electric customer, and the MoOPC appealed certain aspects of the MoPSC decision to the Circuit Court of Pemiscot County, Missouri, the Circuit Court of Stoddard County, Missouri, and the Cole County Circuit Court. The Stoddard and Pemiscot County cases were consolidated (collectively, the Stoddard Circuit Court), and the Cole County case was dismissed. In September 2009, the Stoddard Circuit Court granted Noranda’s request to stay the electric rate increase granted by the January 2009 MoPSC order as it applies specifically to Noranda’s electric service account until the court renders its decision on the appeal. From the granting of the stay request until June 2010, Noranda paid into the Stoddard Circuit Court’s registry the entire amount of its monthly base rate increase and monthly FAC payments. In June 2010, when the May 2010 electric rate order became effective, Noranda ceased making base rate payments into the Stoddard Circuit Court’s registry. Noranda has continued to pay into the Stoddard Circuit Court’s registry its monthly FAC payments relating to electric service during the time periods prior to the effectiveness of the May 2010 electric rate order. Because of the lag between accumulations of changes in net fuel costs and when those net fuel costs are recovered through FAC charges applied to customers’ bills, a portion of Noranda’s FAC payment in January 2012 is expected to be the last contested amount deposited into the Stoddard Circuit Court’s registry relating to this 2009 electric rate order appeal. As of March 31, 2011, the aggregate amount held in the Stoddard Circuit Court’s registry was approximately $13 million.

In August 2010, the Stoddard Circuit Court issued a judgment that reversed parts of the MoPSC’s decision. Also, upon issuance, the Stoddard Circuit Court suspended its own judgment. Therefore, the entire amount currently held in the Stoddard Circuit Court’s registry will remain in the Stoddard Circuit Court’s registry pending the appeal discussed below.

In September 2010, Ameren Missouri filed an appeal with the Missouri Court of Appeals, Southern District. The Missouri Court of Appeals will conduct an independent review of the MoPSC’s order. Ameren Missouri believes the Stoddard Circuit Court’s judgment, which reversed parts of the MoPSC decision, will be found erroneous by the Court of Appeals; however, there can be no assurances that Ameren Missouri’s appeal will be successful. If Ameren Missouri prevails on all issues of its appeal, Ameren Missouri will receive all of the funds held in the Stoddard Circuit Court’s registry, plus accrued interest. If Ameren Missouri were to conclude that some portion of the funds held in the Stoddard Circuit Court’s registry becomes probable of refund to Noranda, a charge to earnings would be recorded for the estimated amount of refund in the period in which that determination was made. A decision by the Missouri Court of Appeals is not expected before the third quarter of 2011.

2010 Electric Rate Order

In May 2010, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of approximately $230 million, including $119 million to cover higher fuel costs and lower revenue from sales outside Ameren Missouri’s system.

The MIEC and MoOPC appealed certain aspects of the MoPSC order to the Cole County Circuit Court. In addition to the MIEC appeal, four industrial customers, who are members of MIEC, also filed a request for a stay with the Cole County Circuit Court. In December 2010, the Cole County Circuit Court granted the request of the four industrial customers to stay the MoPSC’s 2010 electric rate order and required those customers to pay into the Cole County Circuit Court’s registry the difference between their billings under the 2010 Missouri electric rate order and their billings under a Missouri electric rate order that became effective in June 2007, the last Ameren Missouri rate order for which appeals have been exhausted. On February 15, 2011, the four industrial customers posted the bond required by the stay. Since the bond was posted, the four industrial customers have made payments into the Cole County Circuit Court’s registry equal to the difference between their billings under 2010 electric rates, which includes the FAC, and 2007 electric rates. As of March 31, 2011, the aggregate amount held by the Cole County Circuit Court, excluding the bond amount, was approximately $3 million.

20

On February 16, 2011, the MoOPC and the MIEC separately made filings with the MoPSC in which each argued that the stay granted by the Cole County Circuit Court in December 2010 should apply to all Ameren Missouri customers rather than to just the four industrial customers that requested the stay. The MoOPC requested the MoPSC suspend Ameren Missouri’s currently effective rate schedules (approved by the 2010 Missouri electric rate order) and replace them with Ameren Missouri’s previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. The MIEC requested the MoPSC suspend Ameren Missouri’s currently effective rate schedules (approved by the 2010 Missouri electric rate order), including the FAC, and replace them with Ameren Missouri’s rate schedules approved by the MoPSC in its 2007 electric rate order for all customers. On March 16, 2011, the MoPSC denied the MoOPC’s request to suspend Ameren Missouri’s currently effective rate schedules for all customers. By denying the MoOPC’s request, the MoPSC effectively denied the MIEC’s request to suspend currently effective rates as well. The MoOPC and the MIEC then asked the Missouri Court of Appeals, Western District, to require the MoPSC to suspend Ameren Missouri’s currently effective rate schedules (approved by the 2010 Missouri electric rate order) and to replace them with Ameren Missouri’s previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. The Missouri Court of Appeals denied the request. On March 28, 2011, the MoOPC and MIEC made the same request to apply the stay granted to four industrial customers to all Ameren Missouri electric customers to the Cole County Circuit Court. On April 12, 2011, the Cole County Circuit Court denied the motion filed by the MoOPC and MIEC. The Cole County Circuit Court’s April 12, 2011 order concluded that the stay only granted the request of the four industrial customers to pay into the Cole County Circuit Court’s registry the difference between their billings under the 2010 Missouri electric rate order and their billings under the 2007 Missouri electric rate order and that the language in the stay on which the March 28, 2011 motion by the MIEC and MoOPC was based was not part of the operative language of the stay and therefore the stay did not require Ameren Missouri to cease charging the rates approved by the 2010 Missouri electric rate order to all Ameren Missouri electric customers.

With respect to further judicial proceedings regarding the 2010 electric rate order, Ameren Missouri will continue to address the merits of the order and any further filings that might be made relating to the stay, if any, through the judicial and regulatory review processes. We cannot predict the ultimate outcome of these proceedings, which could have a material effect on Ameren Missouri’s and Ameren’s results of operations, financial position, and liquidity.

The stay in effect for the four industrial customers does not address the merits of the appeals of the MoPSC’s 2010 electric rate order or the 2009 electric rate order, which will be addressed in the ordinary course of the judicial review process. At this time, Ameren Missouri 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 Ameren Missouri’s customers. If Ameren Missouri were to conclude that some portion of these rate increases become probable of refund to Ameren Missouri’s customers, a charge to earnings would be recorded for the estimated amount of refund in the period in which that determination was made. A decision is expected to be issued on the MIEC’s and MoOPC’s appeal by the Cole County Circuit Court in 2011.

Pending Electric Rate Case

In September 2010, Ameren Missouri filed a request with the MoPSC to increase its annual revenues for electric service. The currently pending request, as amended in April 2011, seeks an increase of approximately $200 million. This increase request was based primarily on energy infrastructure investments, costs incurred to implement environmental controls and other costs incurred for system-wide reliability improvements for customers. Of the amended request, approximately $106 million relates to recovery of the cost of installing and operating two scrubbers at Ameren Missouri’s Sioux plant. Also included in this requested increase, as amended, is an approximately $40 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 the requested increase in normalized net fuel costs would have been reflected in rate adjustments implemented under Ameren Missouri’s FAC. Capital additions relating to enhancements at the rebuilt Taum Sauk facility were also included in the amended increase request. The amended electric rate increase request was based on a 10.7% return on equity, a capital structure composed of 52.2% common equity, an aggregate electric rate base of $6.7 billion, and a test year ended March 31, 2010, with certain pro-forma adjustments through the true-up date of February 28, 2011. Ameren Missouri also requested continued use of its existing vegetation management and infrastructure cost tracker and the regulatory tracking mechanism for pension and postretirement benefit costs authorized by the MoPSC in earlier electric rate orders.

Ameren Missouri has agreed to settlements of various issues, which are subject to approval by the MoPSC. Ameren Missouri agreed to withdraw its request to implement an infrastructure investment tracking mechanism for certain projects beyond their in-service dates. Ameren Missouri also agreed to withdraw its request to recover its investments in energy efficiency programs over three years instead of six. Ameren Missouri continues to seek the ability to recover any under-recovery of fixed costs resulting from implementation of energy efficiency measures.

In April 2011, the MoPSC staff revised its initial rate recommendation in Ameren Missouri’s pending electric rate case. The MoPSC staff now recommends an increase to Ameren Missouri’s annual revenues of $86 million based on a midpoint return on equity of 8.75%. Included in this recommendation was approximately $33 million of asset disallowances relating to the Sioux plant scrubbers. Other parties have also made recommendations through testimony filed in this case.

21

The MoPSC has several important issues to consider in this case. Those issues include determining the appropriate return on equity, any asset disallowances related to the Sioux plant scrubbers or enhancements at the rebuilt Taum Sauk facility and the timing of the recoverability of the property taxes associated with those assets, and whether Ameren Missouri should be able to continue to employ its existing FAC at the current 95% sharing level.

A decision by the MoPSC in this proceeding is required by July 2011. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve or whether any rate change that may eventually be approved will be sufficient to enable Ameren Missouri to recover its costs and earn a reasonable return on its investments when the rate change goes into effect.

FAC Prudence Review

Missouri law requires the MoPSC to complete prudence reviews of Ameren Missouri’s FAC at least every 18 months. On April 27, 2011, the MoPSC issued an order with respect to its prudency review of Ameren Missouri’s FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri due to the loss of Noranda’s load caused by a severe ice storm in January 2009.

Ameren Missouri disagrees with the MoPSC order’s classification of these sales and believes that the terms of its FAC tariff do not provide for the inclusion of these sales in the FAC calculation. Ameren Missouri intends to seek rehearing of the MoPSC’s order and, if necessary, to appeal this order through the judicial process. We cannot predict the ultimate outcome of the regulatory or judicial proceedings.

As a result of the order, Ameren Missouri will record, in the quarter ended June 30, 2011, a pretax charge to earnings of $17 million for its obligation to refund to Ameren Missouri’s electric customers the earnings associated with these sales previously recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009.

Ameren Missouri recognized an additional $25 million of pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC has not completed a prudency review of the FAC for this subsequent period. Consequently, the MoPSC order issued on April 27, 2011, did not involve any pretax earnings associated with the same long-term partial requirements contracts subsequent to September 30, 2009. Ameren Missouri is reviewing the MoPSC order and is assessing whether it believes the earnings it recognized associated with these sales subsequent to September 30, 2009, are probable of refund to its electric customers. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri’s electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made.

Illinois

Pending Electric and Natural Gas Delivery Service Rate Cases

AIC filed a request with the ICC in February 2011 to increase its annual revenues for electric delivery service by $60 million. The electric rate increase request was based on an 11.25% return on equity, a capital structure composed of 53% equity, and a rate base of $2 billion.

AIC also filed a request with the ICC in February 2011 to increase its annual revenues for natural gas delivery service by $51 million. The natural gas rate increase request was based on an 11.0% return on equity, a capital structure composed of 53% equity, and a rate base of $978 million.

In an attempt to limit regulatory lag, AIC also used a future test year, 2012, in each of these rate requests. Additionally, AIC requested a rider mechanism for its pension costs. This requested rider mechanism would allow AIC to recover or refund any difference between pension expense incurred and the amount allowed in rates annually, subject to an annual reconciliation.

A decision by the ICC in these proceedings is required by January 2012. AIC cannot predict the level of any delivery service rate changes the ICC may approve or whether any rate changes that may eventually be approved will be sufficient to enable AIC to recover its costs and earn a reasonable return on its investments when the rate changes go into effect.

Federal

COLA and ESP

In 2008, Ameren Missouri filed an application with the NRC for a COLA for a new 1,600-megawatt nuclear unit at Ameren Missouri’s existing Callaway County, Missouri, nuclear plant site. In 2009, Ameren Missouri suspended its efforts to build a new nuclear unit at its existing Missouri nuclear plant site, and the NRC suspended review of the COLA.

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Ameren Missouri is considering filing an application to obtain an ESP from the NRC at the Callaway nuclear plant site. An ESP approves a specific location for a nuclear facility; however, additional licenses would be required for the specific type and design of nuclear facility to be built at that site. An ESP does not authorize construction of a plant. An ESP is valid for 20 years and potentially could be renewed for up to an additional 20 years. 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.

All of Missouri’s major electric utility providers, including cooperatives, municipals, and other investor-owned utilities and the governor of Missouri, labor and other key stakeholders, support the passage of this legislation. However, passage of the legislation is uncertain.

Should the Missouri legislation be enacted into law, Ameren Missouri plans to file an ESP application with the NRC later in 2011. NRC approval of an ESP application is expected to take three to four years.

As of March 31, 2011, Ameren Missouri had capitalized approximately $67 million relating to its efforts to construct a new nuclear unit. All of these incurred costs will remain capitalized while management assesses all options to maximize the value of its investment in this project. If all efforts are permanently abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination was made.

NOTE 3 - CREDIT FACILITY BORROWINGS AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, drawings under committed bank credit facilities, or commercial paper issuances.

The following tables summarize the borrowing activity and relevant interest rates under credit agreements as of March 31, 2011, and excludes issued letters of credit:

2010 Missouri Credit Agreement ($800 million)	Ameren    (Parent)			AMO			Total
Average daily borrowings outstanding during 2011	$	238		$	-		$	238
Outstanding credit facility borrowings at period end		150			-			150
Weighted-average interest rate during 2011		2.31	%		-			2.31	%
Peak credit facility borrowings during 2011(a)	$	340		$	-		$	340
Peak interest rate during 2011		2.31	%		-			2.31	%
2010 Genco Credit Agreement ($500 million)	Ameren (Parent)			Genco			Total
Average daily borrowings outstanding during 2011	$	-		$	100		$	100
Outstanding credit facility borrowings at period end		-			100			100
Weighted-average interest rate during 2011		-			2.31	%		2.31	%
Peak credit facility borrowings during 2011(a)	$	-		$	100		$	100
Peak interest rate during 2011		-			2.31	%		2.31	%

(a) The timing of peak credit facility borrowings varies by company and therefore the amounts presented by company might not equal the total peak credit facility borrowings for the period. The simultaneous peak credit facility borrowings by the Ameren Companies under all credit facilities during the first three months of 2011 were $440 million.

Neither Ameren nor AIC borrowed under the 2010 Illinois Credit Agreement during the period ended March 31, 2011.

Based on outstanding borrowings under the 2010 Credit Agreements (including reductions for $15 million of letters of credit issued and $334 million of commercial paper borrowings), the aggregate available amount under the 2010 Credit Agreements at March 31, 2011, was $1.5 billion.

Other Agreements

On June 2, 2010, Ameren entered into a $20 million revolving credit facility ($20 Million Facility) that matures on June 1, 2012. The $20 Million Facility has been fully drawn since June 15, 2010. Borrowings under the $20 Million Facility bear interest at a rate equal to the applicable LIBOR plus 2.25% per annum. The obligations of Ameren under the $20 Million Facility are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under the facility.

Commercial Paper

The 2010 Credit Agreements are used to support Ameren’s and Ameren Missouri’s commercial paper programs. Ameren may at its discretion use any of the 2010 Credit Agreements to support its commercial paper program, subject to its applicable sublimit. At March 31, 2011, Ameren had $334 million of commercial paper outstanding, which reduced the available amounts under these facilities. During

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the first three months of 2011, Ameren had average daily commercial paper balances outstanding of $321 million with a weighted-average interest rate of 0.94%. The peak short-term commercial paper outstanding and peak interest rate during the three months was $377 million and 1.46%, respectively.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants. See Note 4 - Credit Facility Borrowings and Liquidity in the Form 10-K for a detailed description of those provisions.

The 2010 Credit Agreements contain conditions to borrowings and issuances of letters of credit, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation), and required regulatory authorizations. In addition, solely as it relates to borrowings under the 2010 Illinois Credit Agreement, it is a condition precedent to any such borrowing that, at the time of and after giving effect to such borrowing, the borrower will not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation. The 2010 Credit Agreements also contain nonfinancial covenants, including restrictions on the ability to incur liens, to transact with affiliates, to dispose of assets, to make investments in or transfer assets to affiliates, and to merge with other entities.

The 2010 Credit Agreements require each of Ameren, Ameren Missouri, AIC and Genco to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of March 31, 2011, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 50%, 47%, 42% and 48%, for Ameren, Ameren Missouri, AIC and Genco, respectively. In addition, under the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1, to be calculated quarterly, as of the end of the most recent four fiscal quarters then ending, in accordance with the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, as applicable. Ameren’s ratio as of March 31, 2011, was 4.8 to 1. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2010 Credit Agreement.

The $20 Million Facility requires Ameren to maintain consolidated indebtedness of not more than 65% of its consolidated capitalization pursuant to a defined calculation set forth in the agreement. As of March 31, 2011, Ameren’s consolidated indebtedness ratio, calculated in accordance with the provisions of the $20 Million Facility, was 50%. Failure by Ameren to satisfy this covenant would constitute an immediate default under the $20 Million Facility but, given the size of the facility, would not trigger an Ameren default under any of the 2010 Credit Agreements or Ameren’s indenture.

None of the Ameren Companies’ credit facilities or financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At March 31, 2011, management believes that the Ameren Companies were in compliance with their credit facilities’ provisions and covenants.

Money Pools

Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.

Utility

Through the utility money pool, Ameren Missouri, AIC and Ameren Services may access the committed credit facilities as both lenders and borrowers. Ameren and AERG may participate in the utility money pool only as lenders. Ameren Services administers the utility money pool and tracks internal and external funds separately. Internal funds are surplus funds contributed to the utility money pool from participants. The primary sources of external funds for the utility money pool are the 2010 Credit Agreements. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings by their affiliates, but increased to the extent that the pool participants have surplus funds or contribute funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. There were no utility money pool borrowings during the three months ended March 31, 2011.

Non-state-regulated Subsidiary

Ameren Services, Resources Company, Genco, AERG, Marketing Company, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization and applicable regulatory short-term

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borrowing authorizations, to access funding from the 2010 Credit Agreements through a non-state-regulated subsidiary money pool agreement. The total amount available to the pool participants at any given time is reduced by the amount of borrowings made by Ameren’s subsidiaries, but is increased to the extent that other pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. See the discussion above for the amount available under the 2010 Credit Agreements at March 31, 2011. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for Ameren’s non-state-regulated activities. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months ended March 31, 2011, was 1.14% (2010 - 0.62%).

See Note 8 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three months ended March 31, 2011.

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

Under DRPlus, pursuant to an effective SEC Form S-3 registration statement, and under our 401(k) plan, pursuant to an effective SEC Form S-8 registration statement, Ameren issued a total of 0.6 million new shares of common stock valued at $17 million in the three months ended March 31, 2011.

Indenture Provisions and Other Covenants

Ameren Missouri’s and AIC’s indenture provisions and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and AIC are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. However, not meeting these ratios would not result in a default under these covenants and provisions. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended March 31, 2011, at an assumed interest rate of 7% and dividend rate of 8%.

	Required Interest Coverage Ratio(a)	Actual Interest Coverage Ratio	Bonds Issuable(b)			Required Dividend Coverage Ratio(c)	Actual Dividend Coverage Ratio	Preferred Stock Issuable
AMO	³2.0	3.5	$	2,243		³2.5	88.4	$	1,755
AIC	³2.0	6.9		3,225	(d)	³1.5	3.3		203

(a) Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.

(b) Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $91 million and $615 million at Ameren Missouri and AIC, respectively.

(c) Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation.

(d) Amount of bonds issuable by AIC based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.

Ameren’s indenture, pursuant to which Ameren’s 8.875% $425 million senior unsecured notes due 2014 were issued, does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 2010 Credit Agreements, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period.

Ameren Missouri, AIC and Genco as well as certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition,

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under Illinois law, AIC may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless AIC has specific authorization from the ICC.

Ameren Missouri’s mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by Ameren Missouri. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.9 billion of free and unrestricted retained earnings at March 31, 2011.

AIC’s articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. AIC committed to FERC to maintain a minimum 30% ratio of common stock equity to total capitalization following the AIC Merger and AERG distribution. As of March 31, 2011, AIC had a ratio of common stock equity to total capitalization of 57%.

Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and/or debt-to-capital ratios in order for Genco to pay dividends, make certain principal or interest payments, make certain loans to or investments in affiliates, or incur additional indebtedness. The following table summarizes these ratios for the 12 months ended and as of March 31, 2011:

	Required Interest Coverage Ratio			Actual Interest Coverage Ratio		Required Debt-to- Capital Ratio			Actual Debt-to- Capital Ratio
Genco		³1.75(a) /2.50(	b)		4.4		£60%(	b)		47	%

(a) A minimum interest coverage ratio of 1.75 is required for Genco to make certain restricted payments, as defined, including specified dividend, principal and interest payments on certain subordinated intercompany borrowings. As of the date of the restricted payment, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.

(b) A minimum interest coverage ratio of 2.50 and for the most recently ended four fiscal quarters a debt-to-capital ratio of no greater than 60% are required for Genco to incur additional indebtedness, as defined, other than permitted indebtedness, as defined. The ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and related interest expense. Money pool borrowings are permitted indebtedness and are not subject to these incurrence tests.

Genco’s debt incurrence-related ratio restrictions and restricted payment limitations under its indenture may be disregarded if both Moody’s and S&P reaffirm their ratings of Genco indenture debt in place at the time of the incurrence of the additional indebtedness after giving effect to such additional indebtedness.

In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.

Off-Balance-Sheet Arrangements

At March 31, 2011, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

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NOTE 5 - OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the three months ended March 31, 2011, and 2010:

	Three Months
	2011		2010
Ameren:(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	6	$	13
Interest income on industrial development revenue bonds		7		7
Interest and dividend income		1		1
Other		2		1
Total miscellaneous income	$	16	$	22
Miscellaneous expense:
Donations	$	2	$	2
Other		3		5
Total miscellaneous expense	$	5	$	7
AMO:
Miscellaneous income:
Allowance for equity funds used during construction	$	5	$	13
Interest income on industrial development revenue bonds		7		7
Interest and dividend income		1		-
Other		-		1
Total miscellaneous income	$	13	$	21
Miscellaneous expense:
Donations	$	1	$	1
Other		2		1
Total miscellaneous expense	$	3	$	2
AIC:
Miscellaneous income:
Allowance for equity funds used during construction	$	1	$	-
Interest and dividend income		-		1
Other		1		1
Total miscellaneous income	$	2	$	2
Miscellaneous expense:
Other	$	1	$	3
Total miscellaneous expense	$	1	$	3
Genco:
Miscellaneous expense:
Other	$	-	$	1
Total miscellaneous expense	$	-	$	1

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

NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, electricity, uranium, and emission allowances. Such price fluctuations may cause the following:

• an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;

• market values of coal, natural gas, and uranium inventories or emission allowances that differ from the cost of those commodities in inventory; and

• actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.

The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.

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The following table presents open gross derivative volumes by commodity type as of March 31, 2011, and December 31, 2010:

	Quantity (in millions, except as indicated)
	NPNS						Cash Flow						Other						Derivatives That Qualify for
Commodity	Contracts(a)						Hedges(b)						Derivatives(c)						Regulatory Deferral(d)
	2011			2010			2011			2010			2011			2010			2011			2010
Coal (in tons)
Ameren(e)		67			73			(f	)		(f	)		(f	)		(f	)		(f	)		(f	)
AMO		41			46			(f	)		(f	)		(f	)		(f	)		(f	)		(f	)
Genco		20			21			(f	)		(f	)		(f	)		(f	)		(f	)		(f	)
Heating oil (in gallons)
Ameren(e)		(f	)		(f	)		(f	)		(f	)		46			55			69			80
AMO		(f	)		(f	)		(f	)		(f	)		(f	)		(f	)		69			80
Genco		(f	)		(f	)		(f	)		(f	)		35			43			(f	)		(f	)
Natural gas (in mmbtu)
Ameren(e)		85			98			(f	)		(f	)		64			21			208			194
AMO		12			13			(f	)		(f	)		2			2			24			21
AIC		72			85			(f	)		(f	)		(f	)		(f	)		184			173
Genco		(f	)		(f	)		(f	)		(f	)		4			3			(f	)		(f	)
Power (in megawatthours)
Ameren(e)		61			63			32			2			43			61			11			18
AMO		2			2			(f	)		(f	)		(g	)		1			5			5
AIC		(f	)		(f	)		(f	)		(f	)		(f	)		(f	)		22			26
Genco		(f	)		(f	)		(f	)		(f	)		3			3			(f	)		(f	)
Uranium (pounds in thousands)
Ameren		5,810			5,810			(f	)		(f	)		(f	)		(f	)		310			185
AMO		5,810			5,810			(f	)		(f	)		(f	)		(f	)		310			185

(a) Contracts through December 2014, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of March 31, 2011.

(b) Contracts through May 2014 for power as of March 31, 2011.

(c) Contracts through December 2013, October 2012, and December 2014 for heating oil, natural gas, and power, respectively, as of March 31, 2011.

(d) Contracts through December 2013, October 2016, May 2014 and November 2011 for heating oil, natural gas, power, and uranium, respectively, as of March 31, 2011.

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

(f) Not applicable.

(g) Less than 1 million.

Authoritative guidance regarding derivative instruments requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 7 - Fair Value Measurements for our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our coal and purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.

If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income.

Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value charged or credited to regulatory assets or regulatory liabilities in the period in which the change occurs. Ameren Missouri and AIC believe derivative gains and losses deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through future rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income in the period in which the change occurs.

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The following table presents the carrying value and balance sheet location of all derivative instruments as of March 31, 2011, and December 31, 2010:

	Balance Sheet Location	Ameren(a)			AMO			AIC			Genco
2011:
Derivative assets designated as hedging instruments
Commodity contracts:
Power	MTM derivative assets	$	5		$	(b	)	$	(b	)	$	-
	Other assets		2			-			-			-
	Total assets	$	7		$	-		$	-		$	-
Derivative liabilities designated as hedging instruments
Commodity contracts:
Power	MTM derivative liabilities	$	2		$	(b	)	$	-		$	-
	Other deferred credits and liabilities		4			-			-			-
	Total liabilities	$	6		$	-		$	-		$	-
Derivative assets not designated as hedging instruments(c)
Commodity contracts:
Heating oil	MTM derivative assets	$	64		$	(b	)	$	(b	)	$	21
	Other current assets		-			38			-			-
	Other assets		37			22			-			11
Natural gas	MTM derivative assets		8			(b	)		(b	)		1
	Other current assets		-			-			1			-
	Other assets		5			-			5			-
Power	MTM derivative assets		59			(b	)		(b	)		10
	Other current assets		-			6			3			-
	Other assets		21			1			2			-
Uranium	MTM derivative assets		1			(b	)		(b	)		-
	Other current assets		-			1			-			-
	Total assets	$	195		$	68		$	11		$	43
Derivative liabilities not designated as hedging instruments(c)
Commodity contracts:
Heating oil	MTM derivative liabilities	$	5		$	(b	)	$	-		$	2
	Other current liabilities		-			3			-			-
	Other deferred credits and liabilities		-			-			-			1
Natural gas	MTM derivative liabilities		83			(b	)		64			3
	Other current liabilities		-			11			-			-
	Other deferred credits and liabilities		66			10			55			-
Power	MTM derivative liabilities		36			(b	)		5			2
	MTM derivative liabilities - affiliates		(b	)		(b	)		179			5
	Other current liabilities		-			3			-			-
	Other deferred credits and liabilities		13			1			146			-
	Total liabilities	$	203		$	28		$	449		$	13
2010:
Derivative assets designated as hedging instruments
Commodity contracts:
Power	MTM derivative assets	$	3		$	(b	)	$	(b	)	$	-
	Other assets		2			-			-			-
	Total assets	$	5		$	-		$	-		$	-
Derivative liabilities designated as hedging instruments
Commodity contracts:
Power	MTM derivative liabilities	$	1		$	(b	)	$	-		$	-
	Total liabilities	$	1		$	-		$	-		$	-
Derivative assets not designated as hedging instruments(c)
Commodity contracts:
Heating oil	MTM derivative assets	$	42		$	(b	)	$	(b	)	$	14
	Other current assets		-			24			-			-
	Other assets		22			13			-			7
Natural gas	MTM derivative assets		4			(b	)		(b	)		1
	Other current assets		-			1			1			-
	Other assets		1			-			1			-
Power	MTM derivative assets		78			(b	)		(b	)		11
	Other current assets		-			8			2			-
	Other assets		20			-			6			-
Uranium	MTM derivative assets		2			(b	)		(b	)		-
	Other current assets		-			2			-			-
	Total assets	$	169		$	48		$	10		$	33

29

	Balance Sheet Location	Ameren(a)			AMO			AIC		Genco
Derivative liabilities not designated as hedging instruments(c)
Commodity contracts:
Heating oil	MTM derivative liabilities	$	12		$	(b	)	$	-	$	4
	Other current liabilities		-			7			-		-
	Other deferred credits and liabilities		1			-			-		-
Natural gas	MTM derivative liabilities		87			(b	)		73		2
	Other current liabilities		-			11			-		-
	Other deferred credits and liabilities		84			13			70		-
Power	MTM derivative liabilities		61			(b	)		9		3
	MTM derivative liabilities - affiliates		(b	)		(b	)		172		5
	Other current liabilities		-			6			-		-
	Other deferred credits and liabilities		7			-			179		-
	Total liabilities	$	252		$	37		$	503	$	14

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

(b) Balance sheet line item not applicable to registrant.

(c) Includes derivatives subject to regulatory deferral.

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in accumulated OCI and regulatory assets or regulatory liabilities as of March 31, 2011, and December 31, 2010:

	Ameren(a)			AMO			AIC			Genco
2011
Cumulative gains (losses) deferred in accumulated OCI:
Power derivative contracts(b)	$	5		$	-		$	-		$	-
Interest rate derivative contracts(c)(d)		(9	)		-			-			(9	)
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Heating oil derivative contracts(e)		48			48			-			-
Natural gas derivative contracts(f)		(134	)		(21	)		(113	)		-
Power derivative contracts(g)		3			3			(325	)		-
Uranium derivative contracts(h)		1			1			-			-
2010:
Cumulative gains (losses) deferred in accumulated OCI:
Power derivative contracts(b)	$	8		$	-		$	-		$	-
Interest rate derivative contracts(c)(d)		(9	)		-			-			(9	)
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Heating oil derivative contracts(e)		19			19			-			-
Natural gas derivative contracts(f)		(165	)		(24	)		(141	)		-
Power derivative contracts(g)		1			3			(352	)		-
Uranium derivative contracts(h)		2			2			-			-

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

(b) Represents net gains associated with power derivative contracts at Ameren. These contracts are a partial hedge of electricity price exposure through May 2014 as of March 31, 2011. Current gains of $6 million and $8 million were recorded at Ameren as of March 31, 2011, and December 31, 2010, respectively.

(c) Includes net gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity, and the gain in OCI is amortized over a 10-year period that began in June 2002. The carrying value at March 31, 2011, and December 31, 2010, was less than $1 million and less than $1 million, respectively. The balance of the gain will be amortized by June 2012.

(d) Includes net losses associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco’s April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. The carrying value at March 31, 2011, and December 31, 2010, was a loss of $10 million and $10 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.

(e) Represents net gains on heating oil derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through December 2013 as of March 31, 2011. Current gains deferred as regulatory liabilities include $29 million and $29 million at Ameren and Ameren Missouri as of March 31, 2011, respectively. Current losses deferred as regulatory assets include $3 million and $3 million at Ameren and Ameren Missouri as of March 31, 2011, respectively. Current gains deferred as regulatory liabilities include $13 million and $13 million at Ameren and Ameren Missouri as of December 31, 2010, respectively. Current losses deferred as regulatory assets include $6 million and $6 million at Ameren and Ameren Missouri as of December 31, 2010, respectively.

(f) Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2016 at Ameren, Ameren Missouri, and AIC, in each case as of March 31, 2011. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and AIC, respectively, as of March 31, 2011. Current losses deferred as regulatory assets include $74 million, $10 million, and $64 million at Ameren, Ameren Missouri and AIC, respectively, as of March 31, 2011. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $84 million, $11 million, and $73 million at Ameren, Ameren Missouri and AIC, respectively, as of December 31, 2010.

(g) Represents net gains associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2013 at Ameren and AIC and through December 2012 at Ameren Missouri, in each case as of March 31, 2011. Current gains deferred as regulatory liabilities include $8 million, $5 million, and $3 million at Ameren, Ameren Missouri and AIC, respectively, as of March 31, 2011. Current losses deferred as regulatory assets include $7 million, $2 million, and $184 million at Ameren, Ameren Missouri and AIC, respectively, as of March 31, 2011. Current gains

30

deferred as regulatory liabilities include $8 million, $6 million, and $2 million at Ameren, Ameren Missouri and AIC, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $13 million, $3 million, and $181 million at Ameren, Ameren Missouri and AIC, respectively, as of December 31, 2010.

(h) Represents net gains on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through November 2011 as of March 31, 2011. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Missouri as of March 31, 2011, respectively. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri as of December 31, 2010, respectively.

Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and reporting daily exposure to senior management.

We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) International Swaps and Derivatives Association agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) North American Energy Standards Board Inc. agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into one of eight groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of March 31, 2011, and December 31, 2010, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.

	Affiliates(a)		Coal Producers		Commodity Marketing Companies		Electric Utilities		Financial Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Retail Companies		Total
2011:
Ameren(b)	$	378	$	24	$	15	$	14	$	117	$	309	$	4	$	78	$	939
AMO		-		13		1		3		9		8		-		-		34
AIC		-		-		4		-		4		-		-		-		8
Genco		-		6		2		1		7		-		3		-		19
2010:
Ameren(b)	$	410	$	30	$	16	$	22	$	72	$	550	$	10	$	75	$	1,182
AMO		-		21		1		2		5		11		1		-		41
AIC		-		-		3		-		1		-		-		-		4
Genco		-		6		2		1		1		-		6		-		16

(a) Primarily comprised of Marketing Company’s exposure to AIC related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty’s liability position. See Note 14–Related Party Transactions in the Form 10-K for additional information on these financial contracts.

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

The following table presents the amount of cash collateral held from counterparties, as of March 31, 2011, and December 31, 2010, based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements:

	Affiliates(a)		Coal Producers		Commodity Marketing Companies		Electric Utilities		Financial Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Retail Companies		Total
2011:
Ameren(a)	$	-	$	-	$	-	$	-	$	33	$	-	$	-	$	-	$	33
2010:
Ameren(a)	$	-	$	-	$	-	$	-	$	-	$	-	$	-	$	1	$	1

(a) Represents amounts held by Marketing Company. As of March 31, 2011, and December 31, 2010, Ameren registrant subsidiaries held no cash collateral.

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The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading and netting agreements. Collateral includes both cash collateral and other collateral held. As of March 31, 2011, other collateral consisted of letters of credit in the amount of $11 million and $4 million held by Ameren and Genco, respectively. As of December 31, 2010, other collateral consisted of letters of credit in the amount of $28 million and $1 million held by Ameren and AIC, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of March 31, 2011, and December 31, 2010:

	Affiliates(a)		Coal Producers		Commodity Marketing Companies		Electric Utilities		Financial Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Retail Companies		Total
2011:
Ameren(b)	$	370	$	7	$	11	$	7	$	65	$	302	$	1	$	78	$	841
AMO		-		3		-		1		6		8		-		-		18
AIC		-		-		3		-		-		-		-		-		3
Genco		-		2		1		1		1		-		1		-		6
2010:
Ameren(b)	$	404	$	10	$	11	$	9	$	59	$	523	$	7	$	71	$	1,094
AMO		-		8		-		1		2		10		-		-		21
AIC		-		-		2		-		-		-		-		-		2
Genco		-		1		1		1		1		-		5		-		9

(a) Primarily comprised of Marketing Company’s exposure to AIC related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty’s liability position. See Note 14–Related Party Transactions in the Form 10-K for additional information on these financial contracts.

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

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of March 31, 2011, and December 31, 2010, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on March 31, 2011, or December 31, 2010, and (2) those counterparties with rights to do so requested collateral:

	Aggregate Fair Value of Derivative Liabilities(a)		Cash Collateral Posted		Potential Aggregate Amount of Additional Collateral Required(b)
2011:
Ameren(c)	$	487	$	97		$                         236
AMO		132		6		76
AIC		196		80		102
Genco		56		6		21
2010:
Ameren(c)	$	431	$	134		$                        274
AMO		105		7		93
AIC		233		109		111
Genco		31		-		28

(a) Prior to consideration of master trading and netting agreements and including NPNS contract exposures.

(b) As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is after consideration of the effects of such agreements.

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

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Cash Flow Hedges

The following table presents the pretax net gain or loss for the three months ended March 31, 2011 and 2010, associated with derivative instruments designated as cash flow hedges. See Note 11 - Other Comprehensive Income for additional information regarding changes in OCI.

	Gain (Loss) Recognized in OCI(a)			Location of (Gain) Loss Reclassified from OCI into Income(b)	(Gain) Loss Reclassified from OCI into Income(b)			Location of Gain (Loss) Recognized in Income(c)	Gain (Loss) Recognized in Income(c)
2011:
Ameren:(d)
Power	$	(4	)	Operating Revenues - Electric	$	1		Operating Revenues - Electric	$	(1	)
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
Genco:
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
2010:
Ameren:(d)
Power	$	26		Operating Revenues - Electric	$	(4	)	Operating Revenues - Electric	$	-
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
Genco:
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-

(a) Effective portion of gain (loss).

(b) Effective portion of (gain) loss on settlements.

(c) Ineffective portion of gain (loss) and amount excluded from effectiveness testing.

(d) Includes amounts from Ameren registrant and nonregistrant subsidiaries.

(e) Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.

(f) Less than $1 million.

Other Derivatives

The following table represents the net change in market value for derivatives not designated as hedging instruments for the three months ended March 31, 2011 and 2010:

		Location of Gain (Loss) Recognized in Income	Gain (Loss) Recognized in Income
			2011			2010
Ameren(a)	Heating oil	Operating Expenses - Fuel	$	19		$	1
	Natural gas (generation)	Operating Expenses - Fuel		-			(1	)
	Power	Operating Revenues - Electric		(2	)		31
		Total	$	17		$	31
AMO	Natural gas (generation)	Operating Expenses - Fuel	$	(1	)	$	1
	Power	Operating Revenues - Electric		-			(1	)
		Total	$	(1	)	$	-
Genco	Heating oil	Operating Expenses - Fuel	$	15		$	1
	Natural gas (generation)	Operating Expenses - Fuel		-			(1	)
	Power	Operating Revenues		-			1
		Total	$	15		$	1

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

33

Derivatives that Qualify for Regulatory Deferral

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three months ended March 31, 2011 and 2010:

		Gain (Loss) Recognized in Regulatory Liabilities  or Regulatory Assets
		2011			2010
Ameren(a)	Heating oil	$	29		$	1
	Natural gas		31			(106	)
	Power		2			(10	)
	Uranium		(1	)		(1	)
	Total	$	61		$	(116	)
AMO	Heating oil	$	29		$	1
	Natural gas		3			(15	)
	Power		-			16
	Uranium		(1	)		(1	)
	Total	$	31		$	1
AIC	Natural gas	$	28		$	(89	)
	Power		27			(133	)
	Total	$	55		$	(222	)

(a) Includes amounts for intercompany eliminations.

As part of the 2007 Illinois Electric Settlement Agreement and subsequent Illinois power procurement processes, AIC entered into financial contracts with Marketing Company. These financial contracts are derivative instruments. They are accounted for as cash flow hedges by Marketing Company and as derivatives that qualify for regulatory deferral by AIC. Consequently, AIC and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities by AIC and OCI by Marketing Company. In Ameren’s consolidated financial statements, all financial statement effects of the derivative instruments entered into among affiliates were eliminated. See Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K for additional information on these financial contracts. The following table presents the fair value of the financial contracts included on AIC’s balance sheet at March 31, 2011, and December 31, 2010:

		2011		2010
AIC	MTM derivative liabilities - affiliates	$	179	$	172
	Other deferred credits and liabilities		146		178
	Total	$	325	$	350

NOTE 7 - FAIR VALUE MEASUREMENTS

We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3. See Note 8 - Fair Value Measurements under Part II, Item 8, of the Form 10-K for additional information of the definition of fair value and the fair value hierarchy.

In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded gains totaling less than $1 million in the first quarter of 2011 and losses totaling less than $1 million in the first quarter of 2010 related to valuation adjustments for counterparty default risk. At March 31, 2011, the counterparty default risk valuation adjustment related to net derivative liabilities totaled $2 million, less than $1 million, $16 million, and less than $1 million for Ameren, Ameren Missouri, AIC and Genco, respectively. At December 31, 2010, the counterparty default risk valuation adjustment related to derivative contracts totaled $2 million, less than $1 million, $21 million, and less than $1 million for Ameren, Ameren Missouri, AIC and Genco, respectively.

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The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of March 31, 2011:

		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
Ameren(a)	Derivative assets - commodity contracts(b):
	Heating oil	$	-	$	-	$	101	$	101
	Natural gas		6		-		7		13
	Power		-		5		82		87
	Uranium		-		-		1		1
	Nuclear Decommissioning Trust Fund(c):
	Equity securities:
	U.S. large capitalization		234		-		-		234
	Debt securities:
	Corporate bonds		-		42		-		42
	Municipal bonds		-		2		-		2
	U.S. treasury and agency securities		-		58		-		58
	Asset-backed securities		-		14		-		14
	Other		-		2		-		2
AMO	Derivative assets - commodity contracts(b):
	Heating oil		-		-		60		60
	Power		-		2		5		7
	Uranium		-		-		1		1
	Nuclear Decommissioning Trust Fund(c):
	Equity securities:
	U.S. large capitalization		234		-		-		234
	Debt securities:
	Corporate bonds		-		42		-		42
	Municipal bonds		-		2		-		2
	U.S. treasury and agency securities		-		58		-		58
	Asset-backed securities		-		14		-		14
	Other		-		2		-		2
AIC	Derivative assets - commodity contracts(b):
	Natural gas		-		-		6		6
	Power		-		-		5		5
Genco	Derivative assets - commodity contracts(b):
	Heating oil		-		-		32		32
	Natural gas		1		-		-		1
	Power		-		-		10		10
Liabilities:
Ameren(a)	Derivative liabilities - commodity contracts(b):
	Heating oil	$	-	$	-	$	5	$	5
	Natural gas		22		-		127		149
	Power		-		4		51		55
AMO	Derivative liabilities - commodity contracts(b):
	Heating oil		-		-		3		3
	Natural gas		9		-		12		21
	Power		-		1		3		4
AIC	Derivative liabilities - commodity contracts(b):
	Natural gas		5		-		114		119
	Power		-		-		330		330
Genco	Derivative liabilities - commodity contracts(b):
	Heating oil		-		-		3		3
	Natural gas		3		-		-		3
	Power		-		-		7		7

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

(b) The derivative asset and liability balances are presented net of counterparty credit considerations.

(c) Balance excludes $1 million of receivables, payables, and accrued income, net.

35

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2010:

		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
Ameren(a)	Derivative assets - commodity contracts(b):
	Heating oil	$	-	$	-	$	64	$	64
	Natural gas		3		-		2		5
	Power		-		17		86		103
	Uranium		-		-		2		2
	Nuclear Decommissioning Trust Fund(c):
	Cash and cash equivalents		1		-		-		1
	Equity securities:
	U.S. large capitalization		228		-		-		228
	Debt securities:
	Corporate bonds		-		40		-		40
	Municipal bonds		-		2		-		2
	U.S. treasury and agency securities		-		50		-		50
	Asset-backed securities		-		14		-		14
	Other		-		1		-		1
AMO	Derivative assets - commodity contracts(b):
	Heating oil		-		-		37		37
	Natural gas		-		-		1		1
	Power		-		3		5		8
	Uranium		-		-		2		2
	Nuclear Decommissioning Trust Fund(c):
	Cash and cash equivalents		1		-		-		1
	Equity securities:
	U.S. large capitalization		228		-		-		228
	Debt securities:
	Corporate bonds		-		40		-		40
	Municipal bonds		-		2		-		2
	U.S. treasury and agency securities		-		50		-		50
	Asset-backed securities		-		14		-		14
	Other		-		1		-		1
AIC	Derivative assets - commodity contracts(b):
	Natural gas		-		-		2		2
	Power		-		-		8		8
Genco	Derivative assets - commodity contracts(b):
	Heating oil		-		-		21		21
	Natural gas		1		-		-		1
	Power		-		-		11		11
Liabilities:
Ameren(a)	Derivative liabilities - commodity contracts(b):
	Heating oil	$	-	$	-	$	13	$	13
	Natural gas		21		-		150		171
	Power		-		19		50		69
AMO	Derivative liabilities - commodity contracts(b):
	Heating oil		-		-		7		7
	Natural gas		9		-		15		24
	Power		-		3		3		6
AIC	Derivative liabilities - commodity contracts(b):
	Natural gas		7		-		136		143
	Power		-		-		360		360
Genco	Derivative liabilities - commodity contracts(b):
	Heating oil		-		-		4		4
	Natural gas		2		-		-		2
	Power		-		-		8		8

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

(b) The derivative asset and liability balances are presented net of counterparty credit considerations.

(c) Balance excludes $1 million of receivables, payables, and accrued income, net.

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In January 2010, the FASB issued amended authoritative guidance regarding fair value measurements. This guidance required disclosures regarding significant transfers into and out of Level 1 and Level 2 fair value measurements. It also required information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. This guidance was effective for us as of January 1, 2010, with the exception of guidance applicable to detailed Level 3 reconciliation disclosures, which became effective for us as of January 1, 2011. The adoption of this guidance did not have a material impact on our results of operations, financial position, or liquidity because it provides enhanced disclosure requirements only.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2011, and 2010:

	Net derivative commodity contracts
	2011												2010
	Ameren			AMO			AIC			Genco			Ameren			AMO			AIC			Genco
Heating oil:
Beginning balance at January 1	$	51		$	30		$	(a	)	$	17		$	60		$	32		$	(a	)	$	21
Realized and unrealized gains (losses):
Included in earnings(b)		22			-			(a	)		15			(2	)		-			(a	)		(2	)
Included in regulatory assets/liabilities		31			31			(a	)		-			(2	)		(1	)		(a	)		-
Total realized and unrealized gains (losses)		53			31			(a	)		15			(4	)		(1	)		(a	)		(2	)
Purchases		1			1			(a	)		-			(1	)		-			(a	)		-
Settlements		(9	)		(5	)		(a	)		(3	)		(1	)		-			(a	)		(1	)
Ending balance at March 31	$	96		$	57		$	(a	)	$	29		$	54		$	31		$	(a	)	$	18
Change in unrealized gains (losses) related to assets/liabilities held at March 31	$	69		$	49		$	(a	)	$	16		$	-		$	(1	)	$	(a	)	$	1
Natural gas:
Beginning balance at January 1	$	(148	)	$	(14	)	$	(134	)	$	-		$	(67	)	$	(6	)	$	(60	)	$	-
Realized and unrealized gains (losses):
Included in earnings(b)		-			-			-			-			-			-			-			1
Included in regulatory assets/liabilities		7			-			7			-			(103	)		(13	)		(90	)		-
Total realized and unrealized gains (losses)		7			-			7			-			(103	)		(13	)		(90	)		1
Purchases		-			-			1			-			(4	)		-			(3	)		(1	)
Settlements		21			2			18			-			12			1			9			-
Ending balance at March 31	$	(120	)	$	(12	)	$	(108	)	$	-		$	(162	)	$	(18	)	$	(144	)	$	-
Change in unrealized gains (losses) related to assets/liabilities held at March 31	$	7		$	1		$	6		$	-		$	(94	)	$	(12	)	$	(83	)	$	-
Power:
Beginning balance at January 1	$	36		$	2		$	(352	)	$	3		$	38		$	(1	)	$	(422	)	$	1
Realized and unrealized gains (losses):
Included in earnings(b)		(3	)		-			-			-			18			-			-			2
Included in OCI		-			-			-			-			24			-			-			-
Included in regulatory assets/liabilities		(2	)		7			(30	)		-			(22	)		12			(167	)		-
Total realized and unrealized gains (losses)		(5	)		7			(30	)		-			20			12			(167	)		2
Purchases		9			-			-			-			13			(1	)		-			(2	)
Sales		(9	)		-			-			-			(7	)		1			-			2
Settlements		-			(6	)		57			-			(10	)		(3	)		35			-
Transfers into Level 3		-			(1	)		-			-			-			-			-			-
Transfers out of Level 3		-			-			-			-			(17	)		(3	)		-			-
Ending balance at March 31	$	31		$	2		$	(325	)	$	3		$	37		$	5		$	(554	)	$	3
Change in unrealized gains (losses) related to assets/liabilities held at March 31	$	9		$	3		$	(25	)	$	-		$	(6	)	$	6		$	(166	)	$	1
Uranium:
Beginning balance at January 1	$	2		$	2		$	(a	)	$	(a	)	$	(2	)	$	(2	)	$	(a	)	$	(a	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(1	)		(1	)		(a	)		(a	)		(1	)		(1	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(1	)		(1	)		(a	)		(a	)		(1	)		(1	)		(a	)		(a	)
Ending balance at March 31	$	1		$	1		$	(a	)	$	(a	)	$	(3	)	$	(3	)	$	(a	)	$	(a	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31	$	(1	)	$	(1	)	$	(a	)	$	(a	)	$	(1	)	$	(1	)	$	(a	)	$	(a	)

(a) Not applicable.

(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.

Transfers out of Level 3 represent existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers into Level 3 represent existing assets and liabilities that were previously classified as a higher level but were recategorized to Level 3 because the lowest significant input became unobservable during the period. Transfers between Level 2 and Level 3 were primarily caused by changes in availability of financial power trades observable in active markets compared with previous periods for the quarters ended March 31, 2011, and 2010. Any reclassifications are reported at the fair value measurement reported at the beginning of the period in which the changes occur. For the quarters ended March 31, 2011, and 2010, there were no transfers into or out of Level 1.

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The Ameren Companies’ carrying amounts of cash and cash equivalents, accounts receivable, short-term borrowings, and accounts payable approximate fair value because of the short-term nature of these instruments. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments.

The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at March 31, 2011, and December 31, 2010:

	March 31, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:(a)(b)
Long-term debt and capital lease obligations (including current portion)	$	7,008	$	7,689	$	7,008	$	7,661
Preferred stock		142		100		142		102
AMO:
Long-term debt and capital lease obligations (including current portion)	$	3,954	$	4,298	$	3,954	$	4,281
Preferred stock		80		61		80		62
AIC:
Long-term debt (including current portion)	$	1,807	$	2,068	$	1,807	$	2,067
Preferred stock		62		39		62		40
Genco:
Long-term debt (including current portion)	$	824	$	835	$	824	$	826

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

(b) Preferred stock not subject to mandatory redemption of the Ameren subsidiaries along with the 20% noncontrolling interest of EEI is recorded in Noncontrolling Interests on the balance sheet.

NOTE 8 - RELATED PARTY TRANSACTIONS

The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our material related party agreements, see Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K.

Joint Ownership Agreement and Asset Transfer

ATXI and AIC have a joint ownership agreement to construct, own, operate, and maintain certain electric transmission assets in Illinois. Under the terms of this agreement, AIC and ATXI are responsible for their applicable share of all costs related to the construction, operation, and maintenance of electric transmission systems. Through this joint ownership agreement, AIC has a variable interest in ATXI, but AIC is not the primary beneficiary. Ameren is the primary beneficiary of ATXI, and therefore consolidates ATXI.

In January 2011, ATXI repaid advances for the construction of transmission assets to AIC in the amount of $52 million, including $3 million of accrued interest.

In March 2011, AIC and ATXI signed an agreement to transfer, at cost, all of ATXI’s construction work in progress assets related to the construction of a transmission line to AIC for $20 million. As of March 31, 2011, AIC had recorded a $20 million payable for this asset transfer, which was included in Accounts Payable - Affiliates on its balance sheet. In April 2011, AIC paid ATXI for these assets.

Collateral Postings

Under the terms of the 2010 and 2009 Illinois power procurement agreements entered into through a RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect AIC in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Ameren Missouri, as a winning supplier of capacity, and Marketing Company, as a winning supplier of capacity and financial energy swaps, may be required to post collateral. As of December 31, 2010 and March 31, 2011, there were no collateral postings required of Ameren Missouri or Marketing Company related to the 2010 and 2009 Illinois power procurement agreements.

Money Pools

See Note 3 - Credit Facility Borrowings and Liquidity for a discussion of affiliate borrowing arrangements.

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The following table presents the impact on Ameren Missouri, AIC and Genco of related party transactions for the three months ended March 31, 2011, and 2010. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K, and the money pool arrangements discussed in Note 3 - Credit Facility Borrowings and Liquidity of this report.

			Three Months
Agreement	Income Statement Line Item		AMO			AIC			Genco
Genco and EEI power supply	Operating Revenues	2011	$	(a	)	$	(a	)	$	239
agreements with Marketing Company		2010		(a	)		(a	)		264
Genco gas sales to Medina Valley	Operating Revenues	2011		(a	)		(a	)		2
		2010		(a	)		(a	)		1
Total Operating Revenues		2011	$	(a	)	$	(a	)	$	241
		2010		(a	)		(a	)		265
AIC power supply agreements with	Purchased Power	2011	$	(a	)	$	46		$	(a	)
Marketing Company		2010		(a	)		73			(a	)
Ameren Services support services	Other Operations and Maintenance	2011	$	31		$	27		$	5
agreement		2010		36			28			7
AFS support services agreement	Other Operations and Maintenance	2011		(a	)		(a	)		(a	)
		2010		1			(b	)		1
Insurance premiums(c)	Other Operations and Maintenance	2011		(b	)		(a	)		-
		2010		1			(a	)		-
Total Other Operations and		2011	$	31		$	27		$	5
Maintenance Expenses		2010		38			28			8
Money pool borrowings (advances)	Interest Charges	2011	$	-		$	-		$	(b	)
		2010		-			-			(b	)

(a) Not applicable.

(b) Amount less than $1 million.

(c) Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.

Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 10 - Callaway Nuclear Plant in this report.

Callaway Nuclear Plant

The following table presents insurance coverage at Ameren Missouri’s Callaway nuclear plant at March 31, 2011. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.

Type and Source of Coverage	Maximum Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	375		$	-
Pool participation		12,219	(a)		118	(b)
	$	15,594	(c)	$	118
Property damage:
Nuclear Electric Insurance Ltd.	$	2,750	(d)	$	23
Replacement power:
Nuclear Electric Insurance Ltd.	$	490	(e)	$	9
Energy Risk Assurance Company	$	64	(f)	$	-

(a) Provided through mandatory participation in an industry-wide retrospective premium assessment program.

(b) Retrospective premium under Price-Anderson. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.

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(c) Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.

(d) Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.

(e) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear plant. Weekly indemnity of $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $3.6 million per week for 71 weeks thereafter.

(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear plant. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 8 - Related Party Transactions for more information on this affiliate transaction.

The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective October 29, 2008. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.

Losses resulting from terrorist attacks are covered under Nuclear Electric Insurance Ltd.’s policies, subject to an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

If losses from a nuclear incident at the Callaway nuclear plant exceed the limits of, or are not covered by, insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We have also entered into various long-term commitments for purchased power and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, natural gas storage 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, Ameren Missouri and Genco, that operate coal-fired power plants. Significant new rules already proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised ambient air quality standards for SO₂ and NO₂ emissions increasing 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; a regulation governing management of CCR and coal ash impoundments; MACT standards for the control of hazardous air pollutants, such as mercury, metals, and acid gases from power plants; revised NSPS for particulate matter, SO₂ and NO_x emissions from new sources; and 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. During 2011, the EPA is also expected to propose NSPS and emission guidelines for greenhouse gas emissions applicable to new and existing electric generating units. These 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

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may result in significant capital expenditures and/or increased operating costs over the next five to ten years for Ameren, Ameren Missouri 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.

The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations and our preliminary assessment of the potential impacts of the EPA’s proposed regulations for CCR, the CATR, and the revised ambient air quality standards for SO₂ and NO₂ emissions as of March 31, 2011. The estimates in the table below assume that CCR will continue to be regarded as nonhazardous. The estimates below do not include the impacts of the MACT standard for the control of mercury and other hazardous air pollutants proposed by the EPA in March 2011 nor the impacts of the new regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures, as our evaluation of those impacts is still ongoing. The estimates shown in the table below could change depending upon additional federal or state requirements, regulation of greenhouse gas emissions, new hourly ambient air quality standards or changes to existing standards for SO₂ and NO₂ emissions, the final requirements under a MACT standard for the control of hazardous air pollutants such as mercury, metals, and acid gases, the requirements under the finalized CATR, finalized regulations under the Clean Water Act, CCR being classified as hazardous, new technology, variations in costs of material or labor, or alternative compliance strategies, among other factors.

	2011		2012 - 2015					2016 - 2020					Total
AMO(a)	$	35	$	850	-	$	1,050	$	1,380	-	$	1,610	$	2,265	-	$	2,695
Genco		125		470	-		580		50	-		60		645	-		765
AERG		10		125	-		160		5	-		10		140	-		180
Ameren	$	170	$	1,445	-	$	1,790	$	1,435	-	$	1,680	$	3,050	-	$	3,640

(a) Ameren Missouri’s expenditures are expected to be recoverable from ratepayers.

The following sections describe the more significant environmental rules that affect our operations.

Clean Air Act

Both federal and state laws require significant reductions in SO₂ and NO_x emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO₂ and NO_x emissions (the CAIR). The CAIR requires generating facilities in 28 states, including Missouri and Illinois, where our generating facilities are located, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO₂ emissions, annual NO_x emissions, and ozone season NO_x emissions. The cap-and-trade program for both annual and ozone season NO_x emissions went into effect on January 1, 2009. The SO₂ emissions cap-and-trade program went into effect on January 1, 2010.

In December 2008, the United States Court of Appeals for the District of Columbia remanded the CAIR to the EPA for further action to remedy the rule’s flaws, but allowed the CAIR’s cap-and-trade programs to remain effective until they are replaced by the EPA. The impact of the decision is that the existing Illinois and Missouri rules to implement the CAIR will remain in effect until the CAIR is revised by the EPA, at which point the Illinois and Missouri rules may be subject to change. In July 2010, the EPA announced the CATR, which, when finalized, will replace CAIR. As proposed, the CATR will establish emission allowance budgets for each of the 31 states subject to the regulation, including Missouri and Illinois and the District of Columbia. With the proposed CATR, the EPA will be abandoning CAIR’s regional approach to cutting emissions and instead set a pollution budget for each of the impacted states based on the EPA’s analysis of each upwind state’s contribution to air quality in downwind states. Emission reductions would be required in two phases beginning in 2012, with further reductions projected in 2014. The EPA estimates that by 2014, the CATR and other state and EPA actions would reduce the SO₂ emissions from power plants by 71% and their NO_x emissions by 52% from 2005 levels. The proposed CATR is complex, as many issues relating to the establishment of state emission budgets, allowance allocations, allowance trading, and implementation are currently unclear. Our review of the proposed regulation is ongoing. The EPA expects the CATR to be finalized in July 2011. The EPA also plans to propose an additional rule governing air pollutant transport in 2011, to become final in 2012.

Separately, in January and June 2010, the EPA finalized new ambient quality standards for SO₂ and NO₂ and also announced plans for further reductions in the annual national ambient air quality standards for ozone and fine particulates. The state of Illinois and the state of Missouri will be required to individually develop attainment plans to comply with the new ambient air quality standards. We are unable to predict the future impact of these regulatory developments on our results of operations, financial position, and liquidity.

In March 2011, the EPA issued proposed rules under the Clean Air Act that establish a MACT standard to control mercury emissions and other hazardous air pollutants, such as acid gases, metals, and particulate matter. The MACT standard sets emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. The EPA estimates that the new rule would result in a 91% reduction in mercury emissions from

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coal-fired power plants. Also, the proposed rule requires reductions in hydrogen chloride emissions, which were not regulated previously, and will require continuous monitoring systems that are currently not in place. The MACT standard does not require a specific control technology to achieve the emission reductions. However, potentially applicable control technologies discussed in the proposed rule include scrubbers, dry sorbent injection, selective catalytic reduction, electrostatic precipitators, activated carbon injection and fabric filters. The MACT standard will apply to each unit at a coal-fired power plant; however, in certain circumstances, emission compliance can be averaged for the entire power plant. The EPA also proposed to revise the NSPS applicable to particulate matter, SO₂ and NO_x. The proposed rules are scheduled to be finalized in November 2011. Compliance is expected to be required no later than 2016 and potentially as early as 2014. This new proposed rule is voluminous and complex and Ameren’s review of its impact is ongoing. Therefore, we cannot predict at this time the capital or operating costs for compliance or whether this rule is prohibitively expensive for any of our coal-fired plants and may impact their expected useful lives. Changes in plant life or operating cost assumptions could result in future asset impairments, if the estimated undiscounted cash flows related to these assets are no longer expected to exceed their carrying values.

The state of Missouri adopted rules to implement the CAIR for regulating SO₂ and NO_x emissions from electric generating facilities. The rules are a significant part of Missouri’s plan to attain existing ambient air quality standards for ozone and fine particulates, and to meet the federal Clean Air Visibility Rule. The rules are expected to reduce NO_x and SO₂ emissions from electric generating facilities in Missouri by 30% and 75% respectively, by 2015. To comply with the Missouri rules, Ameren Missouri will use allowances and install pollution control equipment. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux plant to reduce SO₂ emissions. Ameren Missouri’s current compliance plan includes the installation of six scrubbers within its coal-fired fleet during the next ten years. Ameren Missouri is currently evaluating the EPA’s proposed MACT standard to control mercury emissions and other hazardous air pollutants and, at this time, cannot predict the estimated capital or operating expense for compliance with this new rule.

Similarly, Ameren and Genco are currently evaluating the EPA’s proposed MACT standard to control mercury and other hazardous air pollutants to determine whether the new federal rules and timeline are more stringent than the existing state regulations. That review is ongoing and could require a change in the compliance plan described below, plant closures, and/or additional capital or operating expense for compliance with the new federal rule. Existing Illinois state regulations already required Ameren and Genco to reduce their emissions of mercury under the MPS. Based on our preliminary review of the proposed MACT standard, the scope of the federal standard is broader than the MPS as no exemption exists for smaller coal-fired plants. Additionally, the proposed federal rule appears more stringent than the MPS because it does not authorize compliance demonstrations based on a 12-month rolling average emission calculation as authorized under the MPS.

Under the MPS, as amended, Illinois generators are required to reduce mercury emissions by 90%, NO_x emissions by 50%, and SO₂ emissions by 70% by 2015. To comply with the MPS, Genco and AERG are installing equipment designed to reduce mercury, NO_x, and SO₂ emissions. In 2009, AERG completed the installation of scrubbers at its Duck Creek plant. In 2010, Genco completed the installation of two scrubbers at its Coffeen plant. Genco and AERG will also need to install additional pollution control equipment to meet these new emission reduction requirements under the MPS or the proposed federal MACT standard as they become due. Current plans include installing scrubbers at Genco’s Newton plant with completion expected in late 2013 and spring 2014. Additional plans include optimizing operations of selective catalytic reduction systems for NO_x reduction at Genco’s Coffeen plant and AERG’s E.D. Edwards and Duck Creek plants. Genco’s estimated environmental capital expenditures assume the use of dry sorbent injection SO₂ reduction technology on all coal-fired units at EEI’s Joppa plant, but Genco is also reviewing other options. Capital requirements for some of these technologies, such as dry sorbent injection, would be lower than for scrubbers. Several projects are planned to manage the solid and liquid wastes generated by the SO₂ scrubbers at the Duck Creek and Coffeen plants. Additional facilities and upgrades are planned at all Merchant Generation coal-fired plants to meet the MPS mercury control requirements, and are being evaluated for their ability to meet the requirements of the proposed MACT standard.

Emission Allowances

Both federal and state laws require significant reductions in SO₂ and NO_x emissions that result from burning fossil fuels. The Clean Air Act created marketable commodities called allowances under the Acid Rain Program, the NO_x Budget Trading Program, and the federal CAIR. Electric generating facilities have been allocated SO₂ and NO_x allowances based on past production and the statutory emission reduction goals. Our generating facilities comply with the SO₂ limits through the use and purchase of allowances, through the use of low-sulfur fuels, and through the application of pollution control technology. Our generating facilities comply with the NO_x limits through the use and purchase of allowances and through the application of pollution control technology, including low-NO_x burners, over-fire air systems, combustion optimization, rich-reagent injection, selective noncatalytic reduction systems, and selective catalytic reduction systems.

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See Note 1 - Summary of Significant Accounting Policies for the SO₂ and NO_x emission allowances held and the related SO₂ and NO_x emission allowance book values that were classified as intangible assets as of March 31, 2011.

Environmental regulations, including the CAIR and CATR, the timing of the installation of pollution control equipment, and the level of operations, will have a significant impact on the number of allowances required for ongoing operations. The CAIR requires a reduction in SO₂ emissions by increasing the ratio of Acid Rain Program allowances surrendered. The CATR, which the EPA proposed to replace the CAIR, however, does not rely upon the Acid Rain Program for its allowance allocation program. The proposed CATR would restrict the use of existing SO₂ allowances for achieving compliance with the Acid Rain Program’s SO₂ emission limitations. Consequently, Ameren, Ameren Missouri and Genco do not expect all of their SO₂ allowances will be used in operations.

The CAIR has both an ozone season program and an annual program for regulating NO_x emissions, with separate allowances issued for each program. The CAIR will remain in effect until it is replaced by the CATR, which is expected to become effective in 2012. The following table presents the ozone season and annual NO_x allowances, in tons, granted under the CAIR to our generating facilities in Missouri and Illinois. The NO_x allowances granted under the CATR will not be known until the rule is finalized.

	Missouri(a)						Illinois(a )
	Ozone			Annual			Ozone		Annual		Total
AMO		11,665			26,842			90		93		38,690
Genco		1			3			5,200		12,867		18,071
AERG		(b	)		(b	)		1,368		3,419		4,787
Ameren total		11,666			26,845			6,658		16,379		61,548

(a) Allowances granted for 2011.

(b) Not applicable.

Global Climate Change

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 any 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. As a result of our diverse fuel portfolio, 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 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 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 are required to consider the emissions of greenhouse gases in any air permit application.

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 its 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 in 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

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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. 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.

Although the EPA has stated its intention to regulate greenhouse gas emissions from stationary sources, such as power plants, congressional action could block or delay that effort. In 2011, legislation was introduced in both the U.S. House of Representatives and U.S. Senate that would block the EPA from regulating greenhouse gas emissions from power plants and other stationary sources under the Clean Air Act. Separate legislation has also been introduced in both the U.S. House of Representatives and U.S. Senate that would delay the EPA’s ability to regulate greenhouse gas emissions from stationary sources for two years. Although neither of these bills has been passed into law, Congress continues to discuss limiting the EPA’s ability to regulate greenhouse gases.

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 Ameren Missouri 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, Ameren Missouri 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, Ameren Missouri’s, and Genco’s results of operations, financial position, and liquidity.

The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, the impact on our coal-fired generation plants and our customers’ costs is unknown, but any impact would probably be negative. Our costs of complying with any mandated federal or state greenhouse gas program could have a material impact on our future results of operations, financial position, and liquidity.

NSR and Clean Air Litigation

The EPA is engaged in an enforcement initiative 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. The EPA’s inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act. The request sought detailed operating and maintenance history data with respect to Genco’s Coffeen, Hutsonville, Meredosia, Newton, and Joppa facilities and AERG’s E.D. Edwards and Duck Creek facilities. In 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired power plants. In September 2008, the EPA issued a third Section 114(a) request regarding projects at all of Ameren’s coal-fired power plants in Illinois. We completed our response to the information requests, but we are unable to predict the outcome of this matter.

In January 2010, Ameren Missouri 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 Ameren Missouri’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 Ameren Missouri’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 Ameren Missouri 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, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. At present, the complaint does not include Ameren Missouri’s other coal-fired facilities. Litigation of this matter could take many years to resolve. Ameren Missouri believes its defenses to the allegations described in the complaint as well as the original and amended Notice of Violation are meritorious. Ameren Missouri will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.

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Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren, Ameren Missouri and Genco. A resolution could result in increased capital expenditures for the installation of control technology, increased operations and maintenance expenses, and fines or penalties. However, we are unable to predict the impact at this time.

Clean Water Act

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw greater than 2 million gallons of water per day from a water body and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would need to meet mortality limits for aquatic life impinged on the plant’s intake screens or reduce intake velocity to 0.5 feet per second. The proposed rule also requires plants to meet site-specific entrainment standards or reduce its cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in July 2012, with compliance expected within eight years thereafter. All coal-fired and nuclear generation facilities at Ameren, Ameren Missouri and Genco with cooling water systems are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities as other technology options potentially could meet the site-specific standards. Ameren, Ameren Missouri and Genco are currently evaluating the proposed rule and their assessment of the proposed rule’s impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our electric generating stations.

In September 2009, the EPA announced its plan to revise the effluent guidelines applicable to steam electric generating units under the Clean Water Act. Effluent guidelines are national standards for wastewater discharges to surface water that are developed based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking and has indicated that it expects to issue a proposed rule in July 2012 and finalize the rule in 2014. We are unable at this time to predict the impact of this development.

Remediation

We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. Ameren Missouri and AIC have each been identified by the federal or state governments as a potentially responsible party (PRP) at several contaminated sites. Several of these sites involve facilities that were transferred by our regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003. As part of each transfer, AIC has contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of March 31, 2011, Ameren and AIC owned or were otherwise responsible for 44 former MGP sites in Illinois. All of these sites are in various stages of investigation, evaluation, and remediation. Based on current estimated plans, Ameren and AIC could substantially conclude remediation efforts at most of these sites by 2015. The ICC permits AIC to recover remediation and litigation costs associated with its former MGP sites from its electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred. Costs are subject to annual review by the ICC.

As of March 31, 2011, Ameren and Ameren Missouri own or are otherwise responsible for 10 MGP sites in Missouri and one site in Iowa. Ameren Missouri does not currently have a rate rider mechanism that permits recovery of remediation costs associated with MGP sites from utility customers. Ameren Missouri does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs.

The following table presents, as of March 31, 2011, the estimated probable obligation to remediate these MGP sites.

	Estimate
	Low		High		Recorded    Liability(a)
Ameren	$	131	$	211	$	131
AMO		3		4		3
AIC		128		207		128

(a) Recorded liability represents the estimated minimum probable obligations, as no other amount within the range provided a better estimate.

AIC is responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of March 31, 2011, AIC estimated that obligation at $0.5 million to $6 million. AIC recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. AIC is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of March 31, 2011, AIC recorded a liability of $0.8 million to represent its best estimate of the obligation for these sites.

Ameren Missouri has responsibility for the cleanup of two waste sites in Missouri as a result of federal agency

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mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri along with two other PRPs are currently performing a site investigation. As of March 31, 2011, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren Missouri has a liability of $2 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate. Ameren Missouri’s other active federal agency-mandated cleanup site in Missouri is a site in Cape Girardeau. Ameren Missouri was a customer of an electrical repair and disposal company that previously operated a facility at this site. A trust was established in the early 1990s by several businesses and governmental agencies to fund the cleanup of this site, which was completed in 2005. Ameren Missouri anticipates this trust fund will be sufficient to complete the remaining adjacent off-site clean-up and, therefore, has no recorded liability at March 31, 2011, related to this site.

Ameren Missouri also has a federal agency mandate to complete a site investigation for a site in Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, Ameren Missouri operated a power generating facility adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order on Consent, Ameren Missouri has joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2.

The Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted to the EPA, and a record of decision is expected in 2011. Once the EPA has selected a remedy, it will begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia’s former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection. As of March 31, 2011, Ameren Missouri estimated its obligation at $0.4 million to $10 million. Ameren Missouri has a liability of $0.4 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

In December 2004, AERG submitted a plan to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. In 2010, AERG closed the recycle pond system by transferring water into the Duck Creek reservoir. Closure of the recycle pond was a necessary step in the eventual closure of the ash ponds. Remediation work on the recycle pond was completed in the first quarter of 2011, and therefore no liability exists as of March 31, 2011.

Our operations or those of our predecessor companies involve the use of, disposal of, and in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine whether such practices will result in future environmental commitments or affect our results of operations, financial position, or liquidity.

Ash Management

There has been increased activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could impact future disposal and handling costs at our power plant facilities. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling, of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants to either close surface impoundments such as ash ponds or retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. Additionally, in January 2010, EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and Genco are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. Ameren, Ameren Missouri and Genco also are evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.

In addition, the Illinois EPA has requested that Ameren, Ameren Missouri and Genco establish groundwater monitoring plans for their ash impoundments in Illinois. Ameren and the Illinois EPA have established a framework for closure of ash ponds in Illinois, including the ash ponds at Venice, Hutsonville, and Duck Creek, when such facilities are ultimately taken out of service. In October 2010, the Illinois

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Pollution Control Board approved a site-specific plan for the closure of an ash pond at Genco’s Hutsonville plant. Those closure requirements include capping and covering the pond, groundwater monitoring, and the establishment of alternative groundwater standards. In May 2011, the Illinois EPA approved a site-specific closure and groundwater management plan for the ash ponds at Ameren Missouri’s Venice plant, similar to the approved plan for Hutsonville. Similar closure requirements and groundwater management plans for ash ponds at the Duck Creek plant are being developed. Ameren, Ameren Missouri and Genco have recorded AROs, based on current laws, for the estimated costs of the retirement of their ash ponds.

Pumped-storage Hydroelectric Facility Breach

In December 2005, there was a breach of the upper reservoir at Ameren Missouri’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. Ameren Missouri settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident.

Ameren Missouri 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 or penalties paid to FERC. Ameren Missouri believes that the total cost for cleanup, damage and liabilities, excluding costs to rebuild the upper reservoir, is approximately $208 million, which is the amount Ameren Missouri had paid as of March 31, 2011. As of March 31, 2011, Ameren Missouri had recorded expenses of $36 million, primarily in prior years, for items not covered by insurance. Ameren Missouri recorded a $172 million receivable for amounts recoverable from insurance companies under liability coverage. As of March 31, 2011, Ameren Missouri had received $104 million from insurance companies for liability claims, which reduced the insurance receivable balance subject to liability coverage to $68 million.

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

Until Ameren’s remaining liability insurance claims and the related litigation, as well as its pending regulatory proceeding are resolved, among other things, we are unable to determine the total impact the breach could have on Ameren’s and Ameren Missouri’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 Ameren Missouri’s November 2007 State of Missouri settlement agreement. In that settlement, Ameren Missouri 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 rebuild of the Taum Sauk facility not recovered from property insurers may be recoverable from Ameren Missouri’s electric customers through rates established in rate cases filed subsequent to the in-service date of the rebuilt facility. As of March 31, 2011, Ameren Missouri had capitalized in property and plant Taum Sauk-related costs of $90 million that Ameren Missouri believes qualify for recovery in electric rates under the terms of the November 2007 state of Missouri settlement agreement, and those costs are included in Ameren Missouri’s pending electric rate increase request, as amended. The inclusion of such costs in Ameren Missouri’s electric rates is subject to review and approval by the MoPSC. See Note 2 - Rate and Regulatory Matters for additional information about Ameren Missouri’s pending electric rate case. Any amounts not recovered in electric rates, or otherwise, could result in charges to earnings, which could be material.

Asbestos-related Litigation

Ameren, Ameren Missouri, AIC and EEI have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies, with as many as 212 parties named in some pending cases and as few as two in others. However, in the cases that were pending as of March 31, 2011, the average number of parties was 78.

The claims filed against Ameren, Ameren Missouri, AIC and Genco allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Former CIPS plants are now owned by Genco, and former CILCO plants are now owned by AERG. As a part of the transfer of ownership of the CIPS and CILCO generating plants, CIPS and CILCO, now AIC, contractually agreed to indemnify Genco and AERG, for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.

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The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of March 31, 2011:

Ameren	AMO	AIC	Genco	Total(a)
5	49	64	(b)	83

(a) Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.

(b) As of March 31, 2011, eight asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

At March 31, 2011, Ameren, Ameren Missouri, AIC and Genco had liabilities of $16 million, $6 million, $10 million, and $- million, respectively, recorded to represent their best estimate of their obligations related to asbestos claims.

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 March 31, 2011, the trust fund balance was approximately $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.

Illinois Sales and Use Tax Exemptions and Credits

In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear the case, and the case became final. During the second quarter of 2010, Genco and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. While it is possible that Illinois will take the position that Genco and AERG do not qualify for the manufacturing exemptions and credits, we do not believe that it is probable that Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. Since the second quarter of 2010 through March 31, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $15 million and $10 million, respectively.

The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity.

NOTE 10 - CALLAWAY NUCLEAR PLANT

Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or one-tenth of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel (the NWF fee). Pursuant to this act, Ameren Missouri collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. Ameren Missouri has sufficient installed storage capacity for spent nuclear fuel at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. In March 2010, the DOE submitted a motion to withdraw the Yucca Mountain Repository license application it filed with the NRC. In anticipation of this action, the Nuclear Energy Institute (NEI) in July 2009 formally requested that DOE promptly perform the statutorily required annual fee adequacy review and immediately suspend collection of the NWF fee. The Nuclear Waste Policy Act mandates that DOE compare the revenue generated by the NWF fee with the costs of the waste disposal program and adjust the size of the NWF fee to match the cost of the program. In the past, the cost of the program reviewed by DOE for NWF fee adequacy has been the cost of constructing and operating the Yucca Mountain Repository. The DOE declined to eliminate or reduce the NWF fee. As a result, NEI and the National Association of Regulatory Utility Commissioners (NARUC) filed petitions for review in the United States Court of Appeals for the District of Columbia Circuit seeking suspension of the NWF fee due to the DOE’s motion to withdraw the application. These lawsuits were consolidated, and in December 2010 the court dismissed the petitions for review as moot (with respect to asking DOE to conduct the annual fee adequacy review) and rejected the request to suspend the fee. In March 2011, NEI and 16 of its member companies filed suit in the United States Court of Appeals for the District of Columbia Circuit again challenging the continued collection of the NWF fee. The lawsuit contends that the DOE’s review of the need to continue to collect the NWF fee, which resulted in the dismissal of the earlier lawsuit as moot, is inadequate and that collection of the NWF fee should be suspended. NARUC also filed suit against the DOE in the United States Court of Appeals for the District of Columbia Circuit in March 2011, questioning the veracity of the DOE’s fee adequacy assessment and seeking similar relief.

The DOE has established the Blue Ribbon Commission on America’s Nuclear Future to conduct a comprehensive review of policies for managing certain components of the

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nuclear fuel cycle, including all alternatives for the storage, processing, and disposal of civilian and defense used nuclear fuel, high-level waste, and materials derived from nuclear activities. The Blue Ribbon Commission report will be only advisory and is expected to be submitted by 2012. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life.

In 1984, the DOE entered into a contract with Ameren Missouri to dispose of nuclear waste from its Callaway nuclear plant. As a result of DOE’s failure to build a repository for nuclear waste or otherwise fulfill its contract obligations, Ameren Missouri and other nuclear power plant owners sued DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri seeks to recover approximately $13 million in costs that it incurred through 2009. This amount includes the cost of reracking the Callaway nuclear plant’s spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes that Ameren Missouri would not have incurred had DOE performed its contractual obligations. Ameren Missouri filed its claim in 2004, but its case was formally stayed by the United States Court of Federal Claims until 2010, pending developments in other cases that were more procedurally advanced. Discovery has been scheduled to be completed in July 2011, and the trial is expected to be held by the spring of 2012. In December 2010, Ameren Missouri and DOE began investigating settlement options. At this time, Ameren Missouri is unable to predict the result of the ongoing settlement discussions.

Ameren Missouri intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license from 2024 to 2044. If the Callaway nuclear plant’s license is extended, additional spent fuel storage will be required. Ameren Missouri plans to install a dry spent fuel storage facility at its Callaway nuclear plant and intends to begin transferring spent fuel rods to this facility beginning in 2016.

Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the expiration of the plant’s operating license in 2024. It is assumed that the Callaway nuclear plant site will be decommissioned based on the immediate dismantlement method and removed from service. Ameren and Ameren Missouri have recorded an ARO for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are included in the costs of service used to establish electric rates for Ameren Missouri’s customers. These costs amounted to $7 million in each of the years 2010, 2009, and 2008. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest cost study filed in September 2008 included the minor tritium contamination discovered on the Callaway nuclear plant site, which did not result in a significant increase in the decommissioning cost estimate. Amounts collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant’s decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for Ameren Missouri’s Callaway nuclear plant is reported as Nuclear Decommissioning Trust Fund in Ameren’s Consolidated Balance Sheet and Ameren Missouri’s Balance Sheet. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory asset.

NOTE 11 - OTHER COMPREHENSIVE INCOME

Comprehensive income includes net income as reported on the statements of income and all other changes in common stockholders’ equity, except those resulting from transactions with common stockholders. A reconciliation of net income to comprehensive income for the three months ended March 31, 2011 and 2010 is shown below for Ameren, AIC and Genco. Ameren Missouri’s comprehensive income was composed only of its net income for the three months ended March 31, 2011 and 2010.

	Three Months
	2011			2010
Ameren:(a)
Net income	$	74		$	106
Unrealized net gain on derivative hedging instruments, net of taxes of $1 and $18, respectively		2			28
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $2 and $9, respectively		(4	)		(15	)
Pension and other postretirement activity, net of income taxes (benefit) of $(1) and $1, respectively		(1	)		(1	)
Total comprehensive income, net of taxes	$	71		$	118
Less: Net income attributable to noncontrolling interests, net of taxes		3			4
Total comprehensive income attributable to Ameren Corporation, net of taxes	$	68		$	114

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	Three Months
	2011			2010
AIC:
Net income	$	34		$	48
Pension and other postretirement activity, net of income taxes (benefit) of $- and $-, respectively		(1	)		(1	)
Total comprehensive income, net of taxes	$	33		$	47
Genco:
Net income	$	22		$	24
Pension and other postretirement activity, net of income taxes (benefit) of $- and $2, respectively		1			(1	)
Total comprehensive income, net of taxes	$	23		$	23
Less: Net income attributable to noncontrolling interest, net of taxes		1			1
Total comprehensive income attributable to Genco	$	22		$	22

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

NOTE 12 - RETIREMENT BENEFITS

Ameren’s pension and postretirement plans are funded in compliance with income tax regulations and to achieve federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at December 31, 2010, its estimated investment performance through March 31, 2011, 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. These amounts are estimates which may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.

The following table presents the components of the net periodic benefit cost for Ameren's pension and postretirement benefit plans for the three months ended March 31, 2011, and 2010:

	Pension Benefits(a)						Postretirement Benefits(a)
	Three Months						Three Months
	2011			2010			2011			2010
Service cost	$	20		$	17		$	6		$	5
Interest cost		45			47			15			16
Expected return on plan assets		(54	)		(53	)		(14	)		(14	)
Amortization of:
Prior service cost (benefit)		-			2			(2	)		(2	)
Actuarial loss		11			5			1			2
Net periodic benefit cost	$	22		$	18		$	6		$	7

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

Ameren Missouri, AIC and Genco are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three months ended March 31, 2011, and 2010:

	Pension Costs				Postretirement Costs
	Three Months				Three Months
	2011		2010		2011		2010
AMO	$	14	$	12	$	3	$	3
AIC		5		2		2		3
Genco		2		3		1		1
Other		1		1		-		-
Ameren(a)	$	22	$	18	$	6	$	7

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

NOTE 13 - SEGMENT INFORMATION

Ameren has three reportable segments: Ameren Missouri, Ameren Illinois, and Merchant Generation. The Ameren Missouri segment for Ameren includes all the operations of Ameren Missouri’s business as described in Note 1 - Summary of Significant Accounting Policies. The Ameren Illinois segment for Ameren includes all of the operations of AIC’s business as described in Note 1 - Summary of Significant Accounting Policies. The Merchant Generation segment for Ameren consists primarily of the operations or activities of Genco, including EEI, AERG, Medina Valley and Marketing Company. The category called Other primarily includes Ameren parent company activities, Ameren Services, and ATXI.

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The following table presents information about the reported revenues and specified items included in Ameren’s net income for the three months ended March 31, 2011, and 2010, and total assets as of March 31, 2011, and December 31, 2010.

Three Months	Ameren Missouri		Ameren Illinois		Merchant Generation		Other			Intersegment Eliminations			Consolidated
2011:
External revenues	$	768	$	806	$	334	$	(4	)	$	-		$	1,904
Intersegment revenues		4		2		45		1			(52	)		-
Net income (loss) attributable to Ameren Corporation(a)		21		33		20		(3	)		-			71
2010:
External revenues	$	677	$	909	$	354	$	-		$	-		$	1,940
Intersegment revenues		5		2		74		3			(84	)		-
Net income (loss) attributable to Ameren Corporation(a)		27		35		44		(4	)		-			102
As of March 31, 2011:
Total assets	$	12,342	$	7,361	$	3,932	$	1,356		$	(1,662	)	$	23,329
As of December 31, 2010:
Total assets	$	12,504	$	7,406	$	3,934	$	1,354		$	(1,683	)	$	23,515

(a) Represents net income (loss) available to common stockholders.

NOTE 14 - DISCONTINUED OPERATIONS

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. 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.

AIC has segregated AERG’s operating results and cash flows and presented them separately as discontinued operations in its consolidated statement of income and consolidated statement of cash flows, respectively, for all periods presented prior to October 1, 2010, in this report. Effective October 1, 2010, AIC does not have any significant continuing involvement in the operations of AERG. For Ameren’s financial statements, AERG’s results of operations remain classified as continuing operations. The table below summarizes the operating results of AIC’s former merchant generation subsidiary, AERG, classified as discontinued operations in AIC’s statement of income for the three months ended March 31, 2010:

	2010
Operating revenues	$	91
Operating expenses		67
Operating income		24
Interest charges		5
Income taxes		7
Income from discontinued operations, net of tax	$	12

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q as well as Management’s Discussion and Analysis of Financial Condition and Results of Operations and Risk Factors contained in the Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements. The discussion also provides information about the financial results of the various segments of our business to provide a better understanding of how those segments and their results affect the financial condition and results of operations of Ameren as a whole.

OVERVIEW

Ameren Executive Summary

Ameren’s earnings in the first quarter of 2011 of $71 million, or $0.29 per share, were lower than its earnings in the first quarter of 2010 of $102 million, or $0.43 per share. The decline in first quarter 2011 earnings, compared with the year-ago quarter, was primarily the result of reduced margins in Ameren’s Merchant Generation segment due to lower realized power prices and higher fuel and related transportation costs, increased storm-related expenses for the Ameren Missouri and Ameren Illinois business segments, lower equity-related capitalized financing costs, an unfavorable change in net unrealized MTM activity on derivatives, and lower electric and natural gas sales to native load customers due primary to milder winter temperatures, among other things. Mitigating the impact of these factors in the first quarter of 2011 were the absence in 2011 of recording the effect of a federal tax law change resulting from a U.S. health care reform bill that was enacted in 2010, lower interest expense, and 2010 utility rate changes in Missouri and Illinois.

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Ameren Missouri recently revised its electric rate increase request pending before the MoPSC to reflect updates and settlement of various issues. Ameren Missouri’s amended request seeks an increase of electric rates of approximately $200 million annually. This request is driven by the significant investments Ameren Missouri has made in its electric infrastructure to maintain and to improve the reliability of its system and to provide cleaner energy, consistent with customers’ expectations. Included in Ameren Missouri’s request are costs associated with the newly installed scrubbers on its Sioux power plant, which represent approximately $106 million of Ameren Missouri’s total request, and higher net fuel costs.

AIC has requested a $111 million increase in annual electric and natural gas delivery service revenues based on a future test year ending December 31, 2012. An ICC decision is expected in mid-January 2012 with new rates expected to be effective that same month. 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.

On the Illinois legislative front, AIC is proactively engaged in supporting the advancement of the Energy Infrastructure and Modernization Act. This legislation is designed to benefit the state of Illinois and its electric and natural gas utility customers by providing incentives for substantial new investments that would modernize and upgrade electric and natural gas systems, improve service reliability, enable the delivery of more competitive supply sources of natural gas, and create jobs. These goals would be achieved by authorizing formulaic ratemaking for qualifying utilities by prescriptively establishing a rate of return on equity and allowing for annual resetting of rates, while still providing appropriate regulatory oversight by the ICC. To qualify, AIC would need to commit to investing an incremental $950 million in capital expenditures over a 10-year period. These investments would be incremental to AIC’s average capital expenditures for calendar years 2008 through 2010. AIC would also need to commit to creating 750 jobs either internally or externally and to achieving certain performance improvement goals.

Ameren’s Merchant Generation segment continues to seek and act upon opportunities to market and sell power at premiums to visible market prices, to reduce and eliminate operating and planned capital expenditures, and to take other actions, such as the sale of its Columbia CT facility, to fund the cash needs of that segment and limit its needs for additional external financing.

With respect to environmental matters, 2011 looks to be a pivotal year for federal environmental regulation. In March 2011, the EPA issued proposed rules for retrofitting power plants with MACT to reduce hazardous air pollutants such as mercury and acid gases. Also in March, the EPA issued proposed cooling water standards. Later this year, 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 issue rules for managing CCR and reducing greenhouse gas emissions later this year. These rules are expected to impose additional costs on Ameren and its customers, and these additional costs could be substantial. Ameren has a team of experts actively evaluating these proposed and anticipated environmental standards. The team is focused on ensuring that Ameren meets these standards in the most cost effective manner possible, taking into account outlooks for power prices, delivered fuel costs, and alternative compliance approaches and technologies, among other factors. Ameren is still evaluating the rules proposed by the EPA in March and their impact on each of its generating units, plants and fleet, as applicable. The environmental capital expenditures disclosed in this report are those believed necessary to meet current environmental rules and regulations, as well as Ameren’s assessment of the likely impact of the proposed CATR and CCR rules. In addition to evaluating proposed and anticipated rules, Ameren is actively working with other companies in its industry to develop responses to the EPA’s proposals and meeting with state and federal officials, including members of the United States Congress, in an effort to protect and promote the interests of its customers and shareholders.

Ameren is dedicated to positioning itself for long-term success. Ameren is focused on customer satisfaction and managing its expenditures in a disciplined manner. Ameren remains committed to seeking utility rates and constructive regulatory frameworks that allow the company to recover its costs and provide an opportunity to earn a fair return on its rate-regulated investments. Further, Ameren intends to align its spending consistent with regulatory outcomes and the related cash flows provided by those decisions. At both its rate-regulated and merchant businesses, Ameren remains dedicated to operating in a safe, reliable and environmentally responsible manner.

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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 expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.

• Ameren Missouri 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. 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 has segregated AERG’s operating results and cash flows and presented them separately as discontinued operations in its consolidated statement of income and consolidated statement of cash flows, respectively, for all periods presented prior to October 1, 2010, in this report. For Ameren’s financial statements, AERG’s results of operations remain classified as continuing operations. See Note 14 - Discontinued Operations under Part I, Item 1, of this report for additional information.

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. All tabular dollar amounts are in millions, unless otherwise indicated.

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 I, Item 1, 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 decreased to $71 million, or 29 cents per share, in the first quarter of 2011, from $102 million, or 43 cents per share, in the first quarter of 2010. Net income attributable to Ameren Corporation in the first quarter of 2011 declined in the Merchant Generation, Ameren Missouri, and Ameren Illinois segments by $24 million, $6 million, and $2 million, respectively, from the prior-year period.

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Compared with the first quarter of 2010, first quarter 2011 earnings were negatively affected primarily by the following items:

• 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 (7 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;

• increased operations and maintenance expenses as a result of major winter storms in 2011 (5 cents per share);

• a reduced gain between years from net unrealized MTM activity on nonqualifying power hedges (5 cents per share);

• a reduction in allowance for equity funds used during construction reflecting the 2010 completion of two scrubbers at Ameren Missouri’s Sioux power plant (3 cents per share); and

• the impact of weather conditions in 2011 on electric demand (estimated at 2 cents per share).

Compared with the first quarter of 2010, first quarter 2011 earnings were favorably affected primarily by the following items:

• the absence in 2011 of recording the effect of a federal tax law change resulting from a U.S. health care reform bill that was enacted in 2010 (6 cents per share);

• lower interest expense primarily due to the maturity and repayment of $200 million of Genco’s senior secured notes in November 2010 and the redemption of $66 million of Ameren Missouri’s subordinated deferrable interest debentures in September 2010 (4 cents per share); and

• higher Ameren Missouri electric rates and Ameren Illinois electric and natural gas rates pursuant to orders issued by the MoPSC and the ICC in 2010 respectively. The Ameren Missouri electric rate increase was partially offset by the adoption of the life span depreciation methodology and increased regulatory asset amortization as directed by the rate order (3 cents per share).

The cents per share information presented above is based on average shares outstanding in the first quarter of 2010. For further details regarding the Ameren Companies’ results of operations for the first three months of 2011 and 2010, including explanations of Margins, Other Operations and Maintenance, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income and Expenses, Interest Charges, and Income Taxes, see the major headings below.

Because it is a holding company, net income and cash flows attributable to Ameren Corporation are primarily generated by its principal subsidiaries: Ameren Missouri, AIC, and Genco. The following table presents the contribution by Ameren’s principal subsidiaries to net income attributable to Ameren Corporation for the three months ended March 31, 2011, and 2010:

	Three Months
	2011			2010
Net income(loss):
AMO	$	21		$	27
AIC		33			47
Genco		21			23
Other(a)		(4	)		5
Net income attributable to Ameren Corporation	$	71		$	102

(a) Includes earnings from other merchant generation operations, as well as corporate general and administrative expenses, and intercompany eliminations.

Below is a table of income statement components by segment for the three months ended March 31, 2011, and 2010:

	Ameren   Missouri			Ameren   Illinois			Merchant   Generation			Other /   Intersegment   Eliminations			Total
Three Months 2011:
Electric margin	$	453		$	231		$	182		$	(2	)	$	864
Natural gas margin		29			118			-			(1	)		146
Other revenues		1			-			1			(2	)		-
Other operations and maintenance		(233	)		(168	)		(71	)		9			(463	)
Depreciation and amortization		(100	)		(52	)		(36	)		(7	)		(195	)
Taxes other than income taxes		(73	)		(41	)		(8	)		(3	)		(125	)
Other income		10			1			-			-			11
Interest charges		(54	)		(35	)		(28	)		(2	)		(119	)
Income (taxes) benefit		(11	)		(20	)		(19	)		5			(45	)
Net income (loss)		22			34			21			(3	)		74
Noncontrolling interest and preferred dividends		(1	)		(1	)		(1	)		-			(3	)
Net income (loss) attributable to Ameren Corporation	$	21		$	33		$	20		$	(3	)	$	71
Three Months 2010:
Electric margin	$	439		$	232		$	227		$	(7	)	$	891
Natural gas margin		29			124			-			(1	)		152
Other operations and maintenance		(218	)		(162	)		(73	)		16			(437	)
Depreciation and amortization		(92	)		(54	)		(36	)		(5	)		(187	)

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	Ameren   Missouri			Ameren   Illinois			Merchant   Generation			Other /   Intersegment   Eliminations			Total
Taxes other than income taxes		(68	)		(42	)		(8	)		(3	)		(121	)
Other income and (expenses)		19			(1	)		-			(3	)		15
Interest charges		(59	)		(37	)		(34	)		(2	)		(132	)
Income (taxes) benefit		(22	)		(24	)		(31	)		2			(75	)
Net income (loss)		28			36			45			(3	)		106
Noncontrolling interest and preferred dividends		(1	)		(1	)		(1	)		(1	)		(4	)
Net income (loss) attributable to Ameren Corporation	$	27		$	35		$	44		$	(4	)	$	102

Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and natural gas margins in the three months ended March 31, 2011, compared with the same period in 2010. 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. 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 may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Three Months	Ameren(a)			AMO			AIC			Genco			Other
Electric revenue change:
Effect of weather (estimate)(b)	$	(7	)	$	(5	)	$	(2	)	$	-		$	-
Regulated rates:
Higher rates		52			49			3			-			-
Noranda sales		3			3			-			-			-
Illinois pass-through power supply costs		(31	)		-			(58	)		-			27
Bad debt rider		(2	)		-			(2	)		-			-
Transmission services		5			1			4			-			-
Off-system revenues		21			21			-			-			-
Recovery of FAC under-recovery		40			40			-			-			-
Sales price changes, including hedge effect		(17	)		-			-			(14	)		(3	)
Wholesale revenues		(18	)		(18	)		-			-			-
Reduction in net unrealized MTM gains		(35	)		(1	)		-			(1	)		(33	)
Sales (excluding impact of abnormal weather) and other		4			5			(4	)		(10	)		13
Total electric revenue change	$	15		$	95		$	(59	)	$	(25	)	$	4
Fuel and purchased power change:
Fuel:
Production volume and other	$	(10	)	$	(22	)	$	-		$	8		$	4
FAC under-recovery		(43	)		(43	)		-			-			-
Recovery of FAC under-recovery		(40	)		(40	)		-			-			-
Net unrealized MTM gains		20			-			-			15			5
Price - Merchant Generation		(13	)		-			-			(10	)		(3	)
Purchased power		13			24			-			-			(11	)
Illinois pass-through power supply costs		31			-			58			-			(27	)
Total fuel and purchased power change	$	(42	)	$	(81	)	$	58		$	13		$	(32	)
Net change in electric margins	$	(27	)	$	14		$	(1	)	$	(12	)	$	(28	)
Natural gas margins change:
Effect of weather (estimate)(b)	$	(2	)	$	-		$	(2	)	$	-		$	-
Bad debt rider		(1	)		-			(1	)		-			-
Change in base rates		2			1			1			-			-
Energy efficiency programs and environmental remediation cost riders		(3	)		-			(3	)		-			-
Sales (excluding impact of abnormal weather) and other		(2	)		(1	)		(1	)		-			-
Net change in natural gas margins	$	(6	)	$	-		$	(6	)	$	-		$	-

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

(b) Represents the estimated margin impact resulting from the effects of changes in cooling and heating degree-days on electric and natural gas demand compared to the prior year based on temperature readings from the National Oceanic and Atmospheric Administration.

Ameren Corporation

Ameren’s electric margins decreased by $27 million, or 3%, in the three months ended March 31, 2011, compared with the same period in 2010. The following items had an unfavorable impact on Ameren’s electric margins:

• Reductions in net unrealized MTM gains principally at the Merchant Generation segment (primarily at Marketing Company), largely related to nonqualifying power hedges, which decreased margins by $35 million.

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• A $20 million increase in Ameren Missouri’s net base fuel expense, primarily due to the higher net base fuel cost rates from the 2010 Missouri rate order, which is substantially recovered from its customers through higher base rates. Net base fuel expense is the sum of fuel - production volume and other (-$22 million), purchased power (+$24 million), and off-system revenues (+$21 million) offset by fuel-FAC under-recovery (-$43 million). See below for additional details regarding the FAC.

• Lower wholesale sales at Ameren Missouri due to a reduction in customers and higher-priced contracts, which decreased revenues by $18 million.

• Unfavorable sales price changes, including hedge effect, due to reductions in higher-margin sales at the Merchant Generation segment resulting from the expiration of the 2006 auction power supply agreements on May 31, 2010, and lower market prices resulting in fewer opportunities for economic power sales, which decreased margins by $17 million.

• 8% higher fuel prices in the Merchant Generation segment, primarily due to higher commodity and transportation costs associated with new supply contracts, which decreased margins by $13 million.

• Unfavorable weather conditions, as evidenced by a 4% decrease in heating degree-days, which decreased revenues by $7 million.

• Excluding the impact of Ameren Missouri’s increased sales to Noranda and the estimated impact of abnormal weather, rate-regulated retail sales volumes decreased by less than 1% which decreased margins by $4 million.

The following items had a favorable impact on Ameren’s electric margins in the three months ended March 31, 2011, compared with the same period in 2010:

• Higher electric base rates at Ameren Missouri, effective June 2010, and higher electric delivery service rates at AIC, effective in May and November 2010, which increased margins by $52 million, in the aggregate.

• Net unrealized MTM activity primarily at the Merchant Generation segment on fuel-related transactions, primarily associated with financial instruments acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts, which increased margins by $20 million.

• Taum Sauk plant’s return to service. Although the Taum Sauk plant was not available to generate electricity for off-system revenues during the first quarter of 2010, Ameren Missouri had included $6 million in the calculation of the FAC as if Taum Sauk had generated off-system revenues. Upon Taum Sauk’s return to service in April 2010, Ameren Missouri’s margins increased by $6 million as a result of the elimination of the adjustment factor from the FAC calculation.

• Higher transmission revenues primarily associated with higher FERC-regulated transmission rates. Higher rates were due, in part, to a significant increase in transmission assets placed into service at AIC, higher equity levels as a result of Ameren’s capital contributions to AIC, and mild 2009 weather, which all impacted the FERC transmission rates that became effective in the second quarter of 2010, which increased 2011 margins by $5 million.

Ameren’s Illinois pass-through power supply costs reflect lower power prices and the expiration of intercompany power supply agreements between AIC and Marketing Company. AIC purchased power from Marketing Company from January 1, 2007, through May 31, 2010, under power supply agreements entered into following a 2006 Illinois power procurement auction. The purchases and sales under these agreements were eliminated in consolidation for Ameren’s financial statements. Subsequent to the expiration of these agreements in May 2010, Marketing Company’s power sales and AIC’s power purchases have primarily been made with nonaffiliated parties. As a result, Ameren’s consolidated revenues decreased by a net $31 million. These revenues were offset by a corresponding $31 million net decrease in purchased power costs.

Ameren Missouri has a FAC cost recovery mechanism that allows Ameren Missouri to recover, through customer rates, 95% of changes in fuel-production volume and other costs 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. Ameren Missouri accrued, as a regulatory asset, $43 million of net fuel and purchase power costs that were greater than the amount set in base rates (FAC under-recovery) in the first quarter of 2011. Under the FAC, Ameren Missouri recovered an additional $40 million from its customers during the first quarter of 2011, with a corresponding offset to fuel expense to reduce the previously recognized FAC regulatory asset. See below for explanations of electric and natural gas margin variances for the Ameren Missouri segment.

Ameren’s natural gas margins decreased $6 million, or 4%, in the three months ended March 31, 2011, compared with the same period in 2010. The following items had an unfavorable impact on Ameren’s natural gas margins:

• A decrease in recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms at AIC, which decreased margins by $3 million. See Operations and Maintenance in this section for information on a related offsetting decrease in energy efficiency program costs and environmental remediation costs.

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• Unfavorable weather conditions, as evidenced by a 4% decrease in heating degree-days, which decreased revenues by $2 million.

• 3% lower sales volumes, excluding the estimated impact of abnormal weather, largely in the commercial and industrial sectors, which decreased margins by $2 million.

• Decrease in recovery of prior years’ bad debt expense through the Illinois bad debt rider at AIC effective March 2010, which resulted in a $1 million decrease in revenues. See Operations and Maintenance in this section for additional information on a related offsetting decrease in bad debt expense.

Ameren’s natural gas margins were favorably impacted by higher net natural gas rates effective early May 2010 and mid-November 2010 at AIC and by an increase in natural gas rates effective February 2011 at Ameren Missouri, which increased margins by $2 million.

Ameren Missouri

Ameren Missouri has a FAC cost recovery mechanism that allows Ameren Missouri to recover, through customer rates, 95% of changes in fuel-production volume and other costs 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. Ameren Missouri accrued, as a regulatory asset, $43 million of net fuel and purchase power costs that were greater than the amount set in base rates (FAC under-recovery) in the first quarter of 2011. Under the FAC, Ameren Missouri recovered an additional $40 million from its customers during the first quarter of 2011, with a corresponding offset to fuel expense to reduce the previously recognized FAC regulatory asset. See below for explanations of electric and natural gas margin variances for the Ameren Missouri segment.

Ameren Missouri’s electric margins increased $14 million, or 3%, in the three months ended March 31, 2011, compared with the same period in 2010. The following items had a favorable impact on Ameren Missouri’s electric margins:

• Higher electric base rates, effective June 2010, which increased margins $49 million.

• Taum Sauk plant’s return to service. Although the Taum Sauk plant was not available to generate electricity for off-system revenues during the first quarter of 2010, Ameren Missouri had included $6 million in the calculation of the FAC as if Taum Sauk had generated off-system revenues. Upon Taum Sauk’s return to service in April 2010, Ameren Missouri’s margins increased by $6 million as a result of the elimination of the adjustment factor from the FAC calculation.

• Increased sales to Noranda as its smelter plant gradually returned to full capacity in March 2010 after a January 2009 severe storm significantly reduced the plant’s capacity, which increased electric revenues by $3 million.

The following items had an unfavorable effect on Ameren Missouri’s electric margins in the three months ended March 31, 2011, compared with the same period in 2010:

• A $20 million increase in net base fuel expense, primarily due to the higher net base fuel cost rates from the 2010 Missouri rate order, which is substantially recovered from its customers through higher base rates. Net base fuel expense is the sum of fuel - production volume and other (-$22 million), purchased power (+$24 million), and off-system revenues (+$21 million) offset by fuel-FAC under-recovery (-$43 million).

• Lower wholesale sales at Ameren Missouri due to a reduction in customers and higher-priced contracts which decreased revenues by $18 million.

• Unfavorable weather conditions, as evidenced by a 5% decrease in heating degree-days, which decreased revenues by $5 million.

Ameren Missouri’s natural gas margins were flat for the three months ended March 31, 2011, compared with the same period in 2010.

Ameren Illinois (AIC)

AIC has a cost recovery mechanism for power purchased on behalf of its customers. These pass-through power costs do not affect margins; however, the electric revenues and offsetting purchased power costs may fluctuate, primarily because of customer switching and usage. See below for explanations of electric and natural gas margin variances for the Ameren Illinois segment.

AIC’s electric margins decreased by $1 million, or less than 1%, in the three months ended March 31, 2011, compared with the same period in 2010. The following items had an unfavorable impact on electric margins:

• Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes increased by 1%, while margins decreased by $3 million due to customer mix. Specifically, increased low-margin industrial sales were offset by reduced high-margin residential and commercial sales.

• Unfavorable weather conditions, as evidenced by a 4% decrease in heating degree-days, which decreased revenues by $2 million.

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• A decrease in recovery of prior years’ bad debt expense under the Illinois bad debt rider effective March 2010, which resulted in a $2 million decrease in revenues. See Operations and Maintenance in this section for additional information on a related offsetting decrease in bad debt expense.

The following items had a favorable effect on AIC’s electric margins in the three months ended March 31, 2011, compared with the same period in 2010:

• Higher transmission revenues primarily associated with higher FERC-regulated transmission rates, which increased 2011 margins by $4 million. Higher rates were due, in part, to a significant increase in transmission assets placed into service, higher equity levels as a result of Ameren’s capital contributions to IP, and mild weather in 2009, which all impacted the FERC transmission rates that became effective in the second quarter of 2010.

• Higher electric delivery service rates, effective in early May 2010 and mid-November 2010, which increased margins by $3 million.

AIC’s natural gas margins decreased by $6 million, or 5%, in the three months ended March 31, 2011, compared with the same period in 2010. The following items had an unfavorable impact on natural gas margins:

• A decrease in recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms, which decreased margins by $3 million. See Operations and Maintenance in this section for information on a related offsetting decrease in energy efficiency program costs and environmental remediation costs.

• Unfavorable weather conditions, as evidenced by a 4% decrease in heating degree-days, which decreased revenues by $2 million.

• A decrease in recovery of prior years’ bad debt expense under the Illinois bad debt rider, effective March 2010, which resulted in a $1 million decrease in revenues. See Operations and Maintenance in this section for additional information on a related offsetting decrease in bad debt expense.

Merchant Generation

Merchant Generation’s electric margins decreased by $45 million, or 20%, in the three months ended March 31, 2011, compared with the same period in 2010. See below for explanations of electric margin variances for the Merchant Generation segment.

Genco

Genco’s electric margins decreased by $12 million, or 8%, in the three months ended March 31, 2011, compared with the same period in 2010. The following items had an unfavorable impact on electric margins:

• Lower revenues allocated to Genco under its power supply agreement (Genco PSA) with Marketing Company. There was a smaller pool of money to allocate because of reductions in higher-margin sales, resulting from the expiration of older long-term contracts and because of lower market prices. However, in accordance with the Genco PSA, Genco was also allocated a higher percentage of revenues from the pool because of higher reimbursable expenses and greater levels of generation relative to AERG. Genco also experienced lower market prices associated with EEI’s power supply agreement with Marketing Company (EEI PSA). The combined impact of lower market prices, including hedge effect, under both power supply agreements reduced electric revenues by $14 million.

• 7% higher fuel prices, primarily due to higher commodity and transportation costs associated with new supply contracts, which reduced margins by $10 million.

• Decreased power plant utilization, primarily due to unplanned outages. The lower production volume decreased electric revenues by $10 million, which was mitigated by lower production volume costs of $8 million. Genco’s baseload coal-fired generating plants’ average capacity factor decreased to 69% in 2011, compared with 72% in 2010, and Genco’s equivalent availability factor decreased to 80% in 2011, compared with 84% in 2010.

Genco’s electric margins were favorably impacted by net unrealized MTM activity on fuel-related transactions primarily associated with financial instruments acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts, which increased margins by $15 million.

Other Merchant Generation

Electric margins from Ameren’s other Merchant Generation operations, primarily AERG and Marketing Company, decreased by $33 million, or 39%, in the three months ended March 31, 2011, compared with the same period in 2010. The following items had an unfavorable impact on electric margins:

• Reductions in net unrealized MTM gains at Marketing Company decreased margins by $33 million primarily related to nonqualifying power hedges.

• Decreased power plant utilization at AERG, primarily due to unplanned outages. Lower production volume decreased electric revenues $8 million, which was offset by lower production volume costs of $4 million. AERG’s

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baseload coal-fired generating plants’ average capacity factor decreased to 75% in 2011, compared with 81% in 2010, while AERG’s equivalent availability factor decreased to 80% in 2011, compared with 87% in 2010.

• 10% higher fuel prices at AERG, primarily due to higher commodity and transportation costs associated with new supply contracts, which reduced margins by $3 million.

• Lower revenues allocated to AERG under its power supply agreement (AERG PSA) with Marketing Company. There was a smaller pool of money to allocate because of reductions in higher-margin sales resulting from the expiration of older long-term contracts and because of lower market prices, including hedge effect. In accordance with the AERG PSA, AERG was allocated a lower percentage of revenues from the pool because of lower reimbursable expenses and lower levels of generation relative to Genco. These items reduced electric revenues by $1 million.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren Corporation

Other operations and maintenance expenses were $26 million higher in the first quarter of 2011, as compared with the first quarter of 2010.

The following items increased other operations and maintenance expenses between periods:

• An $18 million increase in storm repair costs, due to ice storms in 2011.

• An $8 million increase in bad debt expense. Bad debt expense increased primarily because of adjustments under the Ameren Illinois bad debt rider mechanism and because of an increase in reserves due to increased levels of past-due accounts. Expense recorded under the Ameren Illinois bad debt rider mechanism is offset by an equal amount recognized in revenues through customer billings, with no overall effect on net income.

• Increased labor costs of $7 million, primarily because of wage increases and incentive compensation adjustments.

The following items reduced other operations and maintenance expenses between periods:

• Decreased plant maintenance costs of $6 million, primarily because of a major coal-fired plant outage at Ameren Missouri in 2010.

• A $5 million reduction in distribution maintenance expenditures, partially due to weather conditions and the dedication of work crews to storm repair work.

Variations in other operations and maintenance expenses in Ameren’s business segments and for the Ameren Companies for the three months ended March 31, 2011, compared with the same period in 2010, were as follows:

Ameren Missouri

Other operations and maintenance expenses increased $15 million primarily as a result of higher storm repair costs of $11 million, incremental labor costs of $5 million, and higher bad debt expense of $3 million. Mitigating these unfavorable items was a reduction in plant maintenance costs of $6 million, primarily because of a major coal-fired plant outage in 2010.

Ameren Illinois (AIC)

Other operations and maintenance expenses increased $6 million primarily as a result of higher storm repair costs of $7 million, incremental labor costs of $7 million, and higher bad debt expense of $5 million as discussed above. Mitigating these unfavorable items was a reduction in non-storm-related distribution maintenance expenditures of $5 million as discussed above. Additionally, energy efficiency program costs and environmental remediation costs, which are recovered through customer billings, decreased by $3 million. These costs are offset in revenues, with no overall impact on net income.

Merchant Generation

Other operations and maintenance expenses were comparable between periods in the Merchant Generation segment. Other operations and maintenance expenses decreased $4 million at Genco, primarily due to reduced plant maintenance costs associated with outages and other general maintenance work.

Depreciation and Amortization

Ameren Corporation

Ameren’s depreciation and amortization expenses increased $8 million in the first quarter of 2011, as compared with the first quarter of 2010, because of items noted below at the Ameren Companies.

Variations in depreciation and amortization expenses in Ameren’s business segments and for the Ameren Companies for the three months ended March 31, 2011, compared with the same period in 2010, were as follows:

Ameren Missouri

Depreciation and amortization expenses increased $8 million, primarily because of capital additions and an increase

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in Ameren Missouri’s annual depreciation rate due to the adoption of the life span depreciation methodology as a result of the 2010 MoPSC electric rate order.

Ameren Illinois (AIC)

Depreciation and amortization expenses were comparable between periods.

Merchant Generation

Depreciation and amortization expenses were comparable between periods in the Merchant Generation segment and at Genco.

Taxes Other Than Income Taxes

Ameren Corporation

Ameren’s taxes other than income taxes increased $4 million in in the first quarter of 2011, as compared with the first quarter of 2010, because of items noted below at the Ameren Companies. Partially offsetting these unfavorable items was a reduction in payroll taxes.

Variations in taxes other than income taxes in Ameren’s business segments and for the Ameren Companies for the three months ended March 31, 2011, compared with the same period in 2010, were as follows:

Ameren Missouri

Taxes other than income taxes increased $5 million, primarily because of increased property taxes, due to higher state and local assessments, and because of higher gross receipts taxes from increased sales.

Ameren Illinois (AIC)

Taxes other than income taxes were comparable between periods.

Merchant Generation

Taxes other than income taxes were comparable between periods in the Merchant Generation segment and at Genco.

Other Income and Expenses

Ameren Corporation

Miscellaneous income decreased $6 million in the first quarter of 2011, as compared with the first quarter of 2010, because of items noted below at the Ameren Companies. Miscellaneous expense was comparable between periods.

Variations in miscellaneous income, net of expenses, in Ameren’s business segments and for the Ameren Companies for the three months ended March 31, 2011, compared with the same period in 2010, were as follows:

Ameren Missouri

Miscellaneous income decreased $8 million, primarily because of reduced allowance for equity funds used during construction. Allowance for equity funds used during construction was higher in 2010, primarily due to scrubbers being constructed at Ameren Missouri’s Sioux plant, which were placed in service in late 2010. Miscellaneous expense was comparable between periods.

Ameren Illinois (AIC)

Miscellaneous income, net of expenses, was comparable between periods.

Merchant Generation

Miscellaneous income, net of expenses, was comparable between periods in the Merchant Generation segment and at Genco.

Interest Charges

Ameren Corporation

Interest charges decreased $13 million in the first quarter of 2011, as compared with the first quarter of 2010, because of items noted below at the Ameren Companies.

Variations in interest charges in Ameren’s business segments and for the Ameren Companies for the three months ended March 31, 2011, compared with the same period in 2010, were as follows:

Ameren Missouri

Interest charges decreased $5 million, primarily because of the redemption of $66 million of subordinated deferrable interest debentures in September 2010 and reduced amortization of credit facility fees.

Ameren Illinois (AIC)

Interest charges were comparable between periods.

Merchant Generation

Interest charges decreased $6 million in the Merchant Generation segment. Interest charges decreased $2 million at Genco, primarily because of the maturity and repayment of $200 million of senior unsecured notes in November 2010. Interest charges decreased $4 million at AERG, primarily because of reduced intercompany borrowings.

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Income Taxes

The following table presents effective income tax rates for the registrants and by segment for the three months ended March 31, 2011, and 2010:

	Three Months
	2011			2010
Ameren		38	%		41	%
AMO		33			44
AIC		37			40
Genco		41			43
Merchant Generation		45			41

Ameren Corporation

Ameren’s effective tax rate in the first quarter of 2011 was lower than the same period in 2010, primarily due to a noncash, after-tax charge to earnings of $13 million, in the first quarter of 2010 to reduce deferred tax assets. The charge to earnings was recorded because of legislation enacted in the first quarter of 2010 that resulted in retiree health care costs no longer being deductible for tax purposes to the extent an employer’s postretirement health care plan receives federal subsidies that provide retiree prescription drug benefits equivalent to Medicare prescription drug benefits. This was offset, in part, by the impact of an increase in the Illinois statutory tax rate effective at the beginning of 2011.

Variations in effective tax rates in Ameren’s business segments and for the Ameren Companies for the three months ended March 31, 2011, compared with the same period in 2010, were as follows:

Ameren Missouri

Ameren Missouri’s effective tax rate was lower, primarily because of the recording of the effect of the change in tax treatment of retiree health care costs in 2010, offset, in part, by lower favorable net amortization of property-related regulatory assets and liabilities and higher non-deductible expenses in 2011.

Ameren Illinois (AIC)

AIC’s effective tax rate was lower, primarily because of the recording of the effect of the change in tax treatment of retiree health care costs in 2010, along with changes in reserves for uncertain tax positions in 2011, offset, in part, by the increase in the Illinois statutory income tax rate in 2011.

Merchant Generation

The effective tax rate was higher in the Merchant Generation segment, primarily because of the increase in the Illinois statutory income tax rate in 2011, offset, in part, by the recording of the effect of the change in tax treatment of retiree health care costs in 2010.

Genco

Genco’s effective tax rate was lower, primarily because the increase in effective tax rate from the change in tax treatment of retiree health care costs in 2010 was higher than the impact of the increase in the Illinois statutory income tax rate in 2011.

Income from Discontinued Operations, Net of Tax

Ameren Illinois (AIC)

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. 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. 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 remain classified as continuing operations. See Note 14 - Discontinued Operations under Part I, Item 1, of this report for additional information.

LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren’s rate-regulated utility operating companies continue to be a principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail customer mix of primarily rate-regulated residential, commercial, and industrial classes and a commodity mix of natural gas and electric service provide a reasonably predictable source of cash flows for Ameren, Ameren Missouri and AIC. For operating cash flows, Genco, through Marketing Company, sells power through primarily market-based contracts with wholesale and retail customers. In addition to using cash flows from operating activities, the Ameren Companies use available cash, credit facility borrowings, commercial paper issuances, money pool borrowings, or other short-term borrowings from affiliates to support normal operations and other temporary capital requirements. The Ameren Companies may reduce their credit facility or short-term borrowings with cash from operations or, at their discretion, with long-term borrowings or, in the case of Ameren subsidiaries, with equity infusions from

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Ameren. The Ameren Companies expect to incur significant capital expenditures over the next five years as they comply with environmental regulations and make significant investments in their electric and natural gas utility infrastructure to improve overall system reliability. Ameren intends to finance those capital expenditures and investments with a blend of equity and debt so that it maintains a capital structure in its rate-regulated businesses of approximately 50% to 55% equity, assuming constructive regulatory environments. Ameren, Ameren Missouri and AIC plan to implement their long-term financing plans for debt, equity, or equity-linked securities in order to finance their operations appropriately, meet scheduled debt maturities, and maintain financial strength and flexibility. Due to their exposure to changes in power prices and power price uncertainty, Genco and the Merchant Generation segment seek to fund their operations internally and therefore seek to not rely on external financing. Genco and the Merchant Generation segment will continue to seek to defer capital and operating expenses, sell certain assets, and take other actions as necessary to fund their operations internally while maintaining safe and reliable operations. No assurance, however, can be provided that external financing will not be sought.

The following table presents net cash provided by (used in) operating, investing and financing activities for the three months ended March 31, 2011 and 2010:

	Net Cash Provided By Operating Activities							Net Cash (Used In) Investing Activities									Net Cash (Used In) Financing Activities
	2011		2010		Variance			2011			2010			Variance			2011			2010			Variance
Ameren(a)	$	554	$	380	$	174		$	(250	)	$	(317	)	$	67		$	(276	)	$	(325	)	$	49
AMO		65		34		31			(141	)		(190	)		49			(88	)		(56	)		(32	)
AIC		322		142		180			(20	)		(81	)		61			(116	)		(112	)		(4	)
Genco		100		103		(3	)		(100	)		(81	)		(19	)		-			(22	)		22

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

Cash Flows from Operating Activities

Ameren Corporation

Ameren’s cash from operating activities increased in the first three months of 2011 compared with the first three months of 2010. The following items contributed to the increase in cash from operating activities during the first three months of 2011, compared with the same period in 2010:

• A $93 million decrease in collateral posted with counterparties due primarily to the items discussed at the registrant subsidiaries below.

• Ameren Missouri’s FAC under-recovered asset decreased by $87 million as more deferred costs were recovered from customers during 2011.

• Deferred budget billing receivables decreased by $40 million, partially as a result of milder weather, which decreased sales volumes compared with budget-billed amounts.

• A $24 million increase in Illinois electric commodity over-recovered costs caused, in part, by the change in MISO resettlements that occurred in 2011 and 2010, relating to purchased power in the fourth quarter of 2010 and 2009, respectively.

• The nonrecurrence in 2011 of a $10 million donation in 2010 for customer assistance programs required by a 2009 Illinois law that authorized the bad debt rate adjustment mechanism used by AIC.

The following items reduced the increase in Ameren’s cash from operating activities during the first three months of 2011, compared with the same period in 2010:

• Electric and natural gas margins, as discussed in Results of Operations, decreased by $18 million, excluding impacts of noncash MTM transactions.

• A $14 million increase in major storm restoration costs.

• A $9 million increase in property tax payments caused primarily by higher assessed tax values and rates in Missouri.

• Income tax refunds of $5 million were received in 2010, compared with an immaterial income tax payment in 2011.

Ameren Missouri

Ameren Missouri’s cash from operating activities increased in the first three months of 2011 compared with the first three months of 2010. The following items contributed to the increase in cash from operating activities during the first three months of 2011, compared with the same period in 2010:

• The FAC under-recovered asset decreased by $87 million as more deferred costs were recovered from customers during 2011.

• Electric margins, as discussed in Results of Operations, increased by $15 million, excluding impacts of noncash MTM transactions.

• A $5 million decrease in payments associated with major plant outages.

The following items reduced the increase in Ameren Missouri’s cash from operating activities during the first three months of 2011, compared with the same period in 2010:

• A $14 million increase in income tax payments, primarily due to higher 2010 pretax book income.

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• A $12 million increase in collateral posted with counterparties due, in part, to changes in the market price of power and natural gas.

• A $9 million increase in major storm restoration costs.

• A $9 million increase in property tax payments, caused primarily by higher assessed tax values and rates.

• A $5 million increase in receivables held in court registries under the appeals of the MoPSC’s 2009 and 2010 rate orders. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, or this report for additional information.

AIC

AIC’s cash from operating activities associated with continuing operations increased in the first three months of 2011 compared with the first three months of 2010. The following items contributed to the increase in cash from operating activities associated with continuing operations during the first three months of 2011, compared with the same period in 2010:

• A $109 million decrease in collateral posted with counterparties due, in part, to changes in the market price of natural gas.

• An increase in cash collected in 2011 from receivables originating from revenues earned in 2010, compared with 2009 revenues collected in 2010. At December 31, 2010, trade receivables and unbilled revenues were $47 million higher than they were at December 31, 2009, primarily because of higher utility rates and a colder December in 2010, compared with December 2009. The March 31, 2011 and 2010 balances of trade receivables and unbilled revenues were comparable.

• Deferred budget billing balances decreased by $30 million, partially as a result of milder weather, which decreased sales volumes compared with budget-billed amounts.

• A $24 million increase in electric commodity over-recovered costs caused, in part, by the change in MISO resettlements that occurred in 2011 and 2010, relating to purchased power in the fourth quarter of 2010 and 2009, respectively.

• The nonrecurrence in 2011 of a $10 million donation in 2010 for customer assistance programs required by a 2009 Illinois law that authorized the bad debt rate adjustment mechanism.

• A $9 million decrease in income tax payments, primarily due to an acceleration of deductions authorized by enacted economic stimulus legislation.

The following items reduced the increase in AIC’s cash from operating activities associated with continuing operations during the first three months of 2011, compared with the same period in 2010:

• Electric and natural gas margins, as discussed in Results of Operations, decreased by $7 million, excluding impacts of noncash MTM transactions.

• A $5 million increase in major storm restoration costs.

AIC’s cash from operating activities associated with discontinued operations was composed of AERG’s cash flows for all periods prior to October 1, 2010. On that date, AIC distributed AERG to Ameren and, therefore, AIC’s operating cash flows during 2011 did not include AERG.

Genco

Genco’s cash from operating activities decreased in the first three months of 2011 compared with the first three months of 2010. The following items contributed to the decrease in cash from operating activities during the first three months of 2011, compared with the same period in 2010:

• Electric margins, as discussed in Result of Operations, decreased by $26 million, excluding impacts of noncash MTM transactions.

• A $5 million increase in collateral posted with natural gas suppliers due, in part, to a downgrade in credit ratings.

The following items reduced the decrease in Genco’s cash from operating activities during the first three months of 2011, compared with the same period in 2010:

• A $7 million reduction in coal purchases due to reduced coal inventory levels in 2011.

• Income tax refunds of $2 million in 2011, compared with income tax payments of $3 million in 2010. The refund was primarily due to lower pretax book income, deductions relating to environmental expenditures, and an acceleration of depreciation deductions authorized by enacted economic stimulus legislation.

• A $2 million reduction in use tax payments as Genco and EEI claimed tax exemptions and credits for purchase transactions related to their generation operations.

Cash Flows from Investing Activities

Ameren used less cash for investing activities in the first three months of 2011 compared with the first three months of 2010. Net cash used for capital expenditures decreased in 2011 as a result of the completion of two power plant scrubber projects and boiler upgrades in 2010. The reductions in capital expenditures were offset, in part, by an increase in storm restoration costs and the start up costs of a third power plant scrubber project in 2011.

Ameren Missouri’s cash used in investing activities decreased during the first three months of 2011, compared

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with the same period in 2010, principally because of a $45 million decrease in capital expenditures primarily as a result of the completion in 2010 of two scrubbers at its Sioux power plant and boiler upgrades. Partially offsetting this decrease was a $5 million increase in capital expenditures related to storm restoration costs.

AIC’s cash used in investing activities decreased during the first three months of 2011, compared with the same period in 2010, principally because of repayments of advances previously paid to ATXI as a result of the completion of a project under a joint ownership agreement and investing activities related to discontinued operations. Capital expenditures were comparable between periods with a $3 million increase in storm restoration capital expenditures offset by a decrease in maintenance and reliability capital expenditures.

Genco’s cash used in investing activities increased during the first three months of 2011, compared with the same period in 2010. Net cash used for capital expenditures decreased by $5 million primarily as a result of the completion of the Coffeen power plant scrubber project offset by increases related to the startup costs of the Newton power plant scrubber project, with construction beginning in April 2011. During the first quarter of 2011, Genco’s cash provided by operating activities exceeded capital expenditures by $65 million. Genco contributed this surplus to the non-state-regulated subsidiaries’ money pool. During the first quarter of 2010, Genco’s cash provided by operating activities exceeded capital expenditures by $63 million. Genco used this surplus to repay $22 million on an intercompany note payable to Ameren and to contribute to the non-state-regulated subsidiaries’ money pool.

See Note 9 - Commitments and Contingencies under Part I, Item 1, of this report for a discussion of future environmental capital expenditure estimates.

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

Cash Flows from Financing Activities

Ameren’s net cash used in financing activities decreased during the three months ended March 31, 2011, compared with the same period in 2010. To conserve cash at AIC in preparation for repayment of a long-term debt maturity and expected postretirement funding later in 2011, Ameren reduced its repayments of net short-term and credit facility borrowings by $95 million. Partially offsetting the reduction was a $41 million increase in net refunds of advances previously received from generators due to project completion.

Ameren Missouri’s net cash used in financing activities increased during the three months ended March 31, 2011, compared with the same period in 2010, as a result of a $22 million increase in net refunds of advances previously received from generators and a $10 million increase in common stock dividends.

AIC’s net cash used in financing activities during the three months ended March 31, 2011, was comparable to the same period in 2010. In 2011, common stock dividends increased $29 million and net refunds of advances previously received from generators increased $18 million. In 2010, discontinued operations used net cash of $43 million for financing activities.

Genco’s net cash used in financing activities decreased during the three months ended March 31, 2011, compared with the same period in 2010. In 2010, Genco made a $22 million payment on an intercompany note payable to Ameren. In 2011, Genco was able to meet its working capital and investing requirements without utilizing available financing.

Credit Facility Borrowings and Liquidity

The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, drawings under committed bank credit facilities, or commercial paper issuances. See Note 3 - Credit Facility Borrowings and Liquidity under Part I, Item 1, of this report for additional information on credit facilities, short-term borrowing activity, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements, and commercial paper issuances.

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The following table presents the committed bank credit facilities of Ameren and the Ameren Companies, and their availability, as of March 31, 2011:

Credit Facility	Expiration		Amount Committed		Amount Available
Ameren and AMO:
2010 Missouri Credit Agreement(a)(b)		September 2011	$	800	$	635	(c)
Ameren and Genco:
2010 Genco Credit Agreement(a)		September 2013		500		400
Ameren and AIC:
2010 Illinois Credit Agreement(a)		September 2013		800		800
Ameren:
$20 million revolving credit facility		June 2012		20		-

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

(b) This credit agreement expires on September 10, 2013. The borrowing sublimit of Ameren Missouri will mature and expire on September 9, 2011, subject to extension on a 364-day basis, as requested by the borrower and approved by the lenders, or for a longer period upon receipt of any and all required federal or state regulatory approvals, as permitted under this credit agreement, but in no event later than September 10, 2013. Ameren Missouri is seeking state regulatory approval to extend the maturity date of its borrowing sublimit under the 2010 Missouri Credit Agreement to September 10, 2013.

(c) In addition to amounts drawn on these facilities, the amount available is further reduced by standby letters of credit issued under the facilities. The amount of such letters of credit at March 31, 2011, was $15 million.

The 2010 Credit Agreements are used to support Ameren’s and Ameren Missouri’s commercial paper programs. Any of the 2010 Credit Agreements are available to Ameren to support its commercial paper programs, subject to its borrowing sublimit. At March 31, 2011, Ameren had $334 million of commercial paper outstanding, which reduced the available amounts under these facilities. Based on outstanding borrowings under the 2010 Credit Agreements (and considering reductions for $15 million of letters of credit issued and $334 million of commercial paper borrowings), the aggregate available amount under the 2010 Credit Agreements at March 31, 2011, was $1.5 billion.

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In March 2010, FERC issued an order authorizing the issuance of up to $1 billion of short-term debt securities for Ameren Missouri. The authorization was effective as of April 1, 2010, and terminates on March 31, 2012. On October 1, 2010, FERC authorized AIC to issue up to $1 billion of short-term debt securities. The authorization became effective immediately and terminates on September 30, 2012.

Genco has unlimited long and short-term debt issuance authorization from FERC. EEI has unlimited short-term debt authorization from FERC.

The issuance of short-term debt securities by Ameren is not subject to approval by any regulatory body.

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

Long-term Debt and Equity

The Ameren Companies did not have any issuances, redemptions, repurchases or maturities of long-term debt or preferred stock during the first three months of 2011 or 2010. Ameren did issue common stock under its DRPlus and 401(k) plan during the first three months of 2011 and 2010 of $17 million and $20 million, respectively. For additional information see Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report.

In November 2008, Ameren, as a well-known seasoned issuer, along with AIC’s predecessor companies, CIPS, CILCO and IP, and Genco, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in November 2011. As amended in December 2010, Ameren, AIC and Genco may offer securities pursuant to the November 2008 Form S-3 shelf registration statement. In June 2008, Ameren Missouri, as a well-known seasoned issuer, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in June 2011.

A Form S-3 registration statement was filed by Ameren with the SEC in July 2008, and supplemented in December 2010, authorizing the offering of six million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus. Ameren is also selling newly issued shares of common stock under its 401(k) plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus and its 401(k) plan, Ameren issued a total of 0.6 million new shares of common stock valued at $17 million in the three months ended March 31, 2011.

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The Ameren Companies may sell securities registered under their effective registration statements if market conditions and capital requirements warrant such a sale. Any offer and sale will be made only by means of a prospectus that meets the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

Indebtedness Provisions and Other Covenants

See Note 3 - Credit Facility Borrowings and Liquidity and Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report and Note 4 - Credit Facility Borrowings and Liquidity and Note 5 - Long-term Debt and Equity Financings in the Form 10-K for a discussion of covenants and provisions contained in our bank credit facilities and in certain of the Ameren Companies’ indenture agreements and articles of incorporation.

At March 31, 2011, the Ameren Companies were in compliance with their credit facilities, indenture, and articles of incorporation provisions and covenants.

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

Dividends

Ameren paid to its stockholders common stock dividends totaling $93 million, or 38.5 cents per share, during the first three months of 2011 (2010 - $91 million or 38.5 cents per share). On April 21, 2011, Ameren’s board of directors declared a quarterly common stock dividend of 38.5 cents per share payable on June 30, 2011, to stockholders of record on June 8, 2011.

See Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report and Note 4 - Credit Facility Borrowings and Liquidity and Note 5 - Long-term Debt and Equity Financings in the Form 10-K for a discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At March 31, 2011, none of these circumstances existed at the Ameren Companies and, as a result, the Ameren Companies were allowed to pay dividends.

Ameren Missouri, AIC and Genco as well as certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, AIC may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless AIC has specific authorization from the ICC.

The following table presents common stock dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the three months ended March 31, 2011 and 2010:

	Three Months
	2011			2010
AMO	$	68	(a)	$	58
AIC		62	(a)		33
Dividends paid by Ameren	$	93		$	91

(a) Common stock dividends of $37 million paid by Ameren subsidiaries, in the aggregate, were used to reduce Ameren’s short-term debt.

Contractual Obligations

For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K, and Other Obligations in Note 9 - Commitments and Contingencies under Part I, Item 1, of this report. See Note 12 - Retirement Benefits to our financial statements under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan.

At March 31, 2011, total other obligations related to the procurement of coal, natural gas, nuclear fuel, purchased power, methane gas, equipment and meter reading services, and a tax credit obligation, among other agreements, at Ameren, Ameren Missouri, AIC and Genco were $7,401 million, $3,720 million, $2,338 million, and $922 million, respectively. Total unrecognized tax benefits at March 31, 2011, which were not included in the totals above, for Ameren, Ameren Missouri, AIC and Genco were $247 million, $167 million, $53 million, and $21 million, respectively.

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Credit Ratings

The credit ratings of the Ameren Companies affect our liquidity, our access to the capital markets and credit markets, our cost of borrowing under our credit facilities and collateral posting requirements under commodity contracts.

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

	Moody’s		S&P			Fitch
Ameren:
Issuer/corporate credit rating		Baa3		BBB	-		BBB
Senior unsecured debt		Baa3		BB	+		BBB
Commercial paper		P-3		A-3			F2
AMO:
Issuer/corporate credit rating		Baa2		BBB	-		BBB	+
Secured debt		A3		BBB	+		A
AIC:
Issuer/corporate credit rating		Baa3		BBB	-		BBB	-
Secured debt		Baa1		BBB			BBB	+
Senior unsecured debt		Baa3		BBB	-		BBB
Genco:
Issuer/corporate credit rating		-		BBB	-		BBB
Senior unsecured debt		Ba1		BBB	-		BBB

Collateral Postings

Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power, and gas supply, among other things, resulting in a negative impact on earnings. Cash collateral postings and prepayments made with external parties including postings related to exchange-traded contracts at March 31, 2011, were $131 million, $16 million, $87 million, and $6 million at Ameren, Ameren Missouri, AIC, and Genco, respectively. Cash collateral external counterparties posted with Ameren and AIC was $35 million and $2 million, respectively, at March 31, 2011. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at March 31, 2011, could have resulted in Ameren, Ameren Missouri, AIC or Genco being required to post additional collateral or other assurances for certain trade obligations amounting to $236 million, $76 million, $102 million, and $21 million, respectively. As a result of a credit rating downgrade, Genco posted $6 million in collateral with external parties in the first quarter of 2011.

Changes in commodity prices could trigger additional collateral postings and prepayments at current credit ratings. If market prices were 15% higher than March 31, 2011, levels in the next 12 months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, AIC or Genco could be required to post additional collateral or other assurances for certain trade obligations up to approximately $154 million, $12 million, $- million, and $17 million, respectively. If market prices were 15% lower than March 31, 2011, levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, AIC or Genco could be required to post additional collateral or other assurances for certain trade obligations up to approximately $168 million, $6 million, $67 million, and $51 million, respectively.

The cost of borrowing under our credit facilities can also increase or decrease depending upon the credit ratings of the borrower. A credit rating is not a recommendation to buy, sell, or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.

OUTLOOK

Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity for the remainder of 2011 and beyond.

Economy and Capital and Credit Markets

• Although economic conditions in our service territory continued to improve during the first quarter of 2011, the Ameren Companies experienced a reduction in rate-regulated sales volumes, exclusive of increased sales to Noranda and the estimated impact of abnormal weather. In addition, declining natural gas prices and other factors resulted in reduced power prices. A failure to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results and cash flows, new environmental rules and regulations, or a decline of observable industry market multiples in the future could result in the recognition of goodwill or long-lived asset impairment charges.

• In 2011, Ameren’s expected return on plan assets for its pension plan assets and postretirement plan assets is 8% and 7.75%, respectively. To the extent the actual return on investment of Ameren’s pension plan and postretirement plan assets do not achieve their expected return, additional expense will be recognized and additional contributions will be required in subsequent years. Our future expenses and contributions will also be affected by future discount rate levels.

• The Ameren Companies continue to have access to the capital markets at commercially acceptable rates. A future disruption in the capital or credit markets could limit our ability to access the capital and credit markets, upon which our business depends, and result in increased financing costs and more restrictive borrowing terms.

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• Ameren and certain of its subsidiaries have multiyear credit facility agreements. These facilities cumulatively provide $2.1 billion of credit through September 10, 2013, which date is inclusive of the Ameren Missouri borrowing sublimit extension periods provided for in the 2010 Missouri Credit Agreement. The costs of the current credit facility agreements are less than the costs of the facilities they replaced in September 2010.

• At March 31, 2011, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under its credit facility agreements, of approximately $2.1 billion, which was approximately $200 million more than the amount of available liquidity at December 31, 2010.

• Economic conditions could affect the Ameren Companies’ results of operations, financial position and liquidity. See Item 1A. - Risk Factors in the Form 10-K for additional information.

We believe that our liquidity is adequate given our expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect our ability to execute our expected operating, capital or financing plans.

Current Capital Expenditure Plans

• Between 2011 and 2020, Ameren expects to invest up to $3.6 billion, in the aggregate, to retrofit its coal-fired power plants with pollution control equipment in compliance with existing and known environmental laws and regulations. This estimated capital investment could change depending upon additional federal or state requirements, regulation of greenhouse gas emissions, new hourly ambient air quality standards or changes to existing standards for SO₂ and NO₂ emissions, the final requirements under a MACT standard for the control of hazardous air pollutants such as mercury, metals, and acid gases, the requirements under the finalized CATR, finalized regulations under the Clean Water Act, CCR being classified as hazardous, new technology, variations in costs of material or labor, or alternative compliance strategies, among other factors. Any pollution control investments will result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 74% of this investment is expected to be in Ameren Missouri’s operations, and it is therefore expected to be recoverable from ratepayers, subject to prudency reviews. Regulatory lag may materially affect the timing of such recovery and, therefore affect our cash flows and related financing needs. The recoverability of amounts expended in our Merchant Generation operations will depend on whether market prices for power adjust as a result of market conditions reflecting increased environmental costs for coal-fired generators.

• Investments to control emissions at Ameren’s coal-fired power plants to comply with future legislation or regulations would significantly increase future capital expenditures and operations and maintenance expenses, which if excessive could result in the closure of coal-fired power plants, impairment of assets, or otherwise materially adversely affect Ameren’s results of operations, financial position, and liquidity.

• Ameren Missouri continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. Ameren Missouri’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, Ameren Missouri continues to study future generation alternatives, including 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, Ameren Missouri 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 its Callaway nuclear plant site subject to passage of state legislation that would ensure rate recovery of permit costs.

• Ameren Missouri is considering filing an application to obtain an ESP from the NRC at the Callaway nuclear plant site. 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 of up to 20 years, and provide appropriate consumer protections. Should the Missouri legislation be enacted into law, Ameren Missouri plans to file an ESP application with the NRC later in 2011. NRC approval of an ESP application is expected to take three to four years. As of March 31, 2011, Ameren Missouri had capitalized approximately $67 million relating to its efforts to construct a new nuclear unit. All of these incurred costs will remain capitalized while management assesses all options to maximize the value of its investment in this project. If all efforts are permanently abandoned or if management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination was made.

• Ameren Missouri intends to submit a license extension application with the NRC to extend its existing Callaway nuclear plant’s operating license by 20 years so that the license will expire in 2044. Ameren Missouri cannot predict whether or when the NRC will approve the license extension.

• Over the next few years, we expect to make significant investments in our electric and natural gas infrastructure and to incur increased operations and maintenance expenses to improve overall system reliability. We intend to align our operations and maintenance spending and capital investments within our rate-regulated businesses with the revenue and related cash flow levels provided by our regulators. We expect these

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costs or investments at our rate-regulated businesses to be ultimately recovered in rates, subject to prudency reviews by regulators, although rate case outcomes and regulatory lag could materially impact the timing of such recovery and, therefore, our cash flows, related financing needs and the timing in which we are able to proceed with these projects. We are projecting labor and material costs for these capital expenditures will increase over time.

• 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. This investment could total more than $1.3 billion through 2021, with a potential investment of $265 million from 2011 to 2015.

• In September 2010, Resources Company announced that it signed a cooperative agreement with the DOE that could lead to repowering Genco’s Meredosia plant. This would create the world’s first full-scale, oxy-combustion coal-fired power plant designed for permanent CO₂ capture and storage. Ameren and two independent companies will assess the project in phases to validate its 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.

• Any increased investments for environmental compliance, reliability improvement, and new baseload capacity will result in higher depreciation and financing costs.

Revenues

• The earnings of Ameren Missouri and AIC are largely determined by the regulation of their rates by state agencies. Rising costs, including labor, material, depreciation, and financing costs, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, are expected. Ameren, Ameren Missouri and AIC anticipate regulatory lag until their requests to increase rates to recover such costs on a timely basis are granted by state regulators. Ameren, Ameren Missouri and AIC expect to file rate cases frequently.

• In future rate cases, Ameren Missouri and AIC will continue to seek cost recovery and tracking mechanisms from their state regulators to reduce the effects of regulatory lag.

• During 2010, the ICC issued orders that authorized an aggregate $40 million increase in AIC’s annual electric and natural gas delivery service revenues. The rate changes implementing these orders became effective in May for $15 million and November for $25 million.

• AIC filed a request with the ICC in February 2011 to increase its annual revenues for electric delivery service by $60 million. AIC also filed a request with the ICC in February 2011 to increase its annual revenues for natural gas delivery service by $51 million. AIC is using a future test year, 2012, in each of these rate requests, which is designed to reduce regulatory lag. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for additional information. A decision by the ICC in these proceedings is required by January 2012.

• AIC filed a request with FERC in January 2011 to increase its annual revenues for electric delivery service for its wholesale customers by approximately $11 million. AIC provides electric delivery service to nine wholesale customers. These wholesale delivery revenues are treated as a deduction from AIC’s revenue requirement in retail rate filings with the ICC. AIC reached an agreement with one customer prior to the filings, and that customer’s new rates became effective on April 1, 2011. In February 2011, the remaining eight customers filed protests with FERC objecting to the proposed rates. On March 29, 2011, FERC issued an order authorizing the proposed rates to take effect on March 30, 2011, subject to refund when the final rates and corresponding revenue amounts become known after the FERC proceeding concludes, either through settlements reached between customers and AIC, or after the filings are fully litigated. Settlement discussions are ongoing. We cannot predict the ultimate outcome of these filings or their impact on Ameren’s or AIC’s results of operations, financial position, or liquidity.

• Noranda appealed certain aspects of the MoPSC’s January 2009 electric rate order to the Circuit Court of Stoddard County and was granted a stay by the Circuit Court of Stoddard County as it applies specifically to Noranda’s electric service account until the court renders its decision on the appeal. In September 2010, Ameren Missouri filed an appeal with the Missouri Court of Appeals, Southern District. The Missouri Court of Appeals will conduct an independent review of the MoPSC’s January 2009 electric order. A decision by the Missouri Court of Appeals is not expected before the third quarter of 2011.

• In May 2010, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of approximately $230 million, including $119 million to cover higher fuel costs and lower revenue from sales outside Ameren Missouri’s system. The rate changes became effective in June 2010. The provisions of the May 2010 MoPSC order also resulted in the recognition of regulatory assets. These regulatory assets are being amortized over two to five years beginning July 2010. The increased amortization of the regulatory assets and the increase in annual depreciation expense due to the adoption of the

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life span depreciation methodology is estimated to increase Ameren Missouri’s pretax expense by $25 million for all of 2011.

• The MIEC and MoOPC appealed certain aspects of the May 2010 MoPSC order to the Cole County Circuit Court. In addition to the MIEC appeal, four industrial customers, who are members of MIEC, also filed a request for a stay with the Cole County Circuit Court. In December 2010, the Cole County Circuit Court granted the request of the four industrial customers to stay the MoPSC’s 2010 electric rate order and required those customers to pay into the Cole County Circuit Court’s registry the difference between their billings under the 2010 Missouri electric rate order and their billings under a Missouri electric rate order that became effective in June 2007, the last Ameren Missouri rate order for which appeals have been exhausted. On February 15, 2011, the four industrial customers posted the bond required by the stay. Since the bond was posted, the four industrial customers have made payments into the Cole County Circuit Court’s registry equal to the difference between their billings under 2010 electric rates, which include the FAC, and 2007 electric rates. The stay in effect for the four industrial customers does not address the merits of the appeals of the MoPSC’s 2010 electric rate order or the 2009 electric rate order, which will be addressed in the ordinary course of the judicial review process. At this time, Ameren Missouri 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 Ameren Missouri’s customers. If Ameren Missouri were to conclude that some portion of these rate increases become probable of refund to Ameren Missouri’s customers, a charge to earnings would be recorded for the estimated amount of refund in the period in which that determination was made. A decision is expected to be issued on the MIEC’s and MoOPC’s appeal by the Cole County Circuit Court in 2011.

• On February 16, 2011, the MoOPC and the MIEC separately made filings with the MoPSC in which each argued that the stay granted by the Cole County Circuit Court in December 2010 should apply to all Ameren Missouri customers rather than to just the four industrial customers that requested the stay. The MoOPC requested the MoPSC suspend Ameren Missouri’s currently effective rate schedules (approved by the 2010 Missouri electric rate order) and replace them with Ameren Missouri’s previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. The MIEC requested the MoPSC suspend Ameren Missouri’s currently effective rate schedules (approved by the 2010 Missouri electric rate order), including the FAC, and replace them with Ameren Missouri’s rate schedules approved by the MoPSC in its 2007 electric rate order for all customers. On March 16, 2011, the MoPSC denied the MoOPC’s request to suspend Ameren Missouri’s currently effective rate schedules for all customers. By denying the MoOPC’s request, the MoPSC effectively denied the MIEC’s request to suspend currently effective rate schedules as well. The MoOPC and the MIEC then asked the Missouri Court of Appeals, Western District, to require the MoPSC to suspend Ameren Missouri’s currently effective rate schedules (approved by the 2010 Missouri electric rate order) and to replace them with Ameren Missouri’s previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. The Missouri Court of Appeals denied the request. On March 28, 2011, the MoOPC and MIEC made the same request to apply the stay granted to four industrial customers to all Ameren Missouri electric customers to the Cole County Circuit Court. On April 12, 2011, the Cole County Circuit Court denied the motion filed by the MoOPC and MIEC. The Cole County Circuit Court’s April 12, 2011 order concluded that the stay only granted the request of the four industrial customers to pay into the Cole County Circuit Court’s registry the difference between their billings under the 2010 Missouri electric rate order and their billings under the 2007 Missouri electric rate order and that the language in the stay on which the March 28, 2011 motion by the MIEC and MoOPC was based was not part of the operative language of the stay and therefore the stay did not require Ameren Missouri to cease charging the rates approved by the 2010 Missouri electric rate order to all Ameren Missouri electric customers. With respect to further judicial proceedings regarding the 2010 electric rate order, Ameren Missouri will continue to address the merits of the order and any further filings that might be made relating to the stay, if any, through the judicial and regulatory review processes. We cannot predict the ultimate outcome of these proceedings, which could have a material effect on Ameren Missouri’s and Ameren’s results of operations, financial position, and liquidity.

• Ameren Missouri filed a request with the MoPSC in September 2010 to increase its annual revenues for electric service. The currently pending request, as amended in April 2011, seeks an increase of approximately $200 million. Of the amended request, approximately $106 million relates to recovery of the costs of installing and operating two scrubbers at Ameren Missouri’s Sioux plant. Also included in this requested increase, as amended, is an approximately $40 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 the requested increase in normalized net fuel costs would have been reflected in rate adjustments implemented under Ameren Missouri’s FAC. Capital additions relating to enhancements at the rebuilt Taum Sauk facility were also included in the amended increase request. In April 2011, the MoPSC staff revised its initial rate recommendation in Ameren Missouri’s pending rate case. The MoPSC staff now recommends an increase to Ameren

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Missouri’s annual revenues of $86 million based on a midpoint return on equity of 8.75%. Included in this recommendation was approximately $33 million of asset disallowances relating to the Sioux plant scrubbers. Other parties also made recommendations through testimony filed in this case. The MoPSC has several important issues to consider in this case. Those issues include determining the appropriate return on equity, any asset disallowances related to the Sioux plant scrubbers or enhancements at the rebuilt Taum Sauk facility and the timing of the recoverability of the property taxes associated with those assets, and whether Ameren Missouri should be able to continue to employ its existing FAC at the current 95% sharing level. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for additional information. A decision by the MoPSC in this proceeding is required by July 2011.

• In January 2011, the MoPSC approved a stipulation and agreement that resolved a June 2010 request by Ameren Missouri to increase annual natural gas revenues. The stipulation and agreement authorized an increase in annual natural gas delivery revenues of $9 million, which included approximately $2 million of annual revenues previously collected through the ISRS rider for the test year ended December 31, 2009. The new rates became effective on February 20, 2011. The stipulation and agreement approved a revised block-rate structure for residential customers that results in more certainty of margin revenue recovery regardless of weather conditions or conservation efforts as recovery is less dependent on usage.

• Missouri law requires the MoPSC to complete prudence reviews of Ameren Missouri’s FAC at least every 18 months. On April 27, 2011, the MoPSC issued an order with respect to its prudency review of Ameren Missouri’s FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri due to the loss of Noranda’s load caused by a severe ice storm in January 2009. Ameren Missouri disagrees with the MoPSC order’s classification of these sales and believes that the terms of its FAC tariff do not provide for the inclusion of these sales in the FAC calculation. Ameren Missouri intends to seek rehearing of the MoPSC’s order and, if necessary, to appeal this order through the judicial process. We cannot predict the ultimate outcome of the regulatory or judicial proceedings. As a result of the order, Ameren Missouri will record, in the quarter ended June 30, 2011, a pretax charge to earnings of $17 million for its obligation to refund to Ameren Missouri’s electric customers the earnings associated with these sales previously recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009. Ameren Missouri recognized an additional $25 million of pretax earnings associated with these same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC has not completed a prudency review of the FAC for this subsequent period. Consequently, the MoPSC order issued on April 27, 2011, did not involve any pretax earnings associated with the same long-term partial requirements contracts subsequent to September 30, 2009. Ameren Missouri is reviewing the MoPSC order and is assessing whether it believes the earnings it recognized associated with these sales subsequent to September 30, 2009, are probable of refund to its electric customers. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri’s electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made. Ameren Missouri intends to align its operations and maintenance spending and capital investments with the revenue and related cash flow levels provided by its regulators.

• Volatile power prices in the Midwest can affect the amount of revenues Ameren and Genco generate by marketing power into the wholesale and spot markets and can influence the cost of power purchased in the spot markets.

• The availability and performance of Ameren’s and Genco’s Merchant Generation fleet can materially affect their revenues. The Merchant Generation segment expects to have available generation from its coal-fired plants of 34 million megawatthours in 2011 and 2012. However, the Merchant Generation segment’s actual generation levels will be significantly influenced by whether market prices for power in those years justify the generation output, among other things. The Merchant Generation segment expects to generate 29 million megawatthours of power from its coal-fired plants in 2011 (Genco - 22 million) based on expected power prices. Should power prices rise more than expected, the Merchant Generation segment has the capacity and availability to sell more generation.

• The marketing strategy for the Merchant Generation segment is to optimize generation output in a low risk manner to minimize volatility of earnings and cash flow, while seeking to capitalize on its low-cost generation fleet to provide solid, sustainable returns. To accomplish this strategy, the Merchant Generation segment has established hedge targets for near-term years. Through a mix of physical and financial sales contracts, Marketing Company targets to hedge Merchant Generation’s expected output by 80% to 90% for the following year, 50% to 70% for two years out, and 30% to 50% for three years out. As of March 31, 2011, Marketing Company had hedged approximately 27 million megawatthours of Merchant Generation’s expected 2011 generation, at an average price of $45 per megawatthour. For 2012, Marketing Company had hedged approximately 17.5 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $48 per megawatthour. For 2013, Marketing Company had hedged approximately 9 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $42 per megawatthour. Marketing Company has also entered into capacity-only sales contracts for 2011, 2012, and 2013, resulting in expected capacity-only revenues related to these contracts of $47 million, $19 million, and $7 million, respectively. Any unhedged forecasted generation will be exposed to market prices at the time of sale. Prices for power have

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decreased significantly since mid-2008. As a result, any new physical or financial power sales may be at price levels lower than previously experienced.

• In April 2011, Genco reached an agreement to sell its remaining interest in the Columbia CT facility to the city of Columbia, Missouri. The sale is scheduled to be completed by June 1, 2011. Genco expects to receive cash proceeds of $45 million from the sale upon closing. Upon the completion of this sale, the existing power purchase agreements between Marketing Company and the city of Columbia would be terminated. Genco does not expect the sale of the Columbia CT facility to have a material impact on its ongoing earnings.

• Current and future energy efficiency programs developed by Ameren Missouri, AIC and others could result in reduced demand for our electric generation and our electric and natural gas transmission and distribution services. Our regulated operations will seek a regulatory framework that allows either a return on these programs similar to the return that could be earned on supply-side capital investments, or recovery of their costs, within a declining demand environment.

Fuel and Purchased Power

• In 2010, 85% of Ameren’s electric generation (Ameren Missouri - 77%, Genco - 99%) was supplied by coal-fired power plants. About 97% of the coal used by these plants (Ameren Missouri - 97%, Genco - 97%) was delivered by rail from the Powder River Basin in Wyoming. In the past, deliveries from the Powder River Basin have occasionally been restricted because of rail maintenance, weather, and derailments. As of March 31, 2011, coal inventories for Ameren, Ameren Missouri and Genco were at targeted levels. However, Merchant Generation is targeting a reduction in its coal inventory, relative to previous levels, in 2011. Disruptions in coal deliveries could cause Ameren, Ameren Missouri 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, or purchasing power from other sources.

• Ameren’s fuel costs (including transportation) are expected to increase in 2011 and beyond. As of March 31, 2011, the average cost of Merchant Generation’s baseload hedged fuel costs, which include coal, transportation, diesel fuel surcharges, and other charges, was approximately $23.50 per megawatthour in 2011, $24.50 per megawatthour in 2012, and $27 per megawatthour in 2013. The 2013 baseload fuel hedges include a larger proportion of Merchant Generation’s expected burn of Illinois Basin coal and a smaller proportion of Merchant Generation’s expected burn of Powder River Basin coal. The costs associated with Illinois Basin coal is greater than the costs associated with Powder River Basin coal. See Item 3 - Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about the percentage of fuel and transportation requirements that are price-hedged for 2011 through 2015.

Other Costs

• In December 2005, there was a breach of the upper reservoir at Ameren Missouri’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. The rebuilt Taum Sauk plant became fully operational in April 2010. Until Ameren’s remaining liability insurance claims and the related litigation, as well as its pending regulatory proceeding, are resolved, among other things, we are unable to determine the total impact the breach could have on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity beyond those amounts already recognized. Certain costs associated with the Taum Sauk facility not recovered from property insurers are expected to be recoverable from Ameren Missouri’s electric customers. As of March 31, 2011, Ameren Missouri had capitalized in property and plant Taum Sauk-related costs of $90 million that Ameren Missouri believes qualify for recovery in electric rates under the terms of the November 2007 state of Missouri settlement agreement, and those costs are included in Ameren Missouri’s pending electric rate increase request, as amended. The inclusion of such costs in Ameren Missouri’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. See Note 9 - Commitments and Contingencies under Part I, Item 1, of this report for further discussion of Taum Sauk matters.

• Ameren Missouri’s Callaway nuclear plant’s next scheduled refueling and maintenance outage in the fall of 2011 is expected to last approximately 35 days. During a scheduled outage, which occurs every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, compared with non-outage years.

• As an owner of a nuclear plant, Ameren and Ameren Missouri are closely monitoring the nuclear-related developments in Japan resulting from the March 2011 earthquake and tsunami and the review of United States nuclear power plant safety launched by the NRC following the events in Japan. Ameren and Ameren Missouri will participate in implementing any lessons learned from the Japan events and the NRC review, which could result in higher operations and maintenance costs and higher capital costs in the future. At this time, we cannot predict the ultimate outcome of those developments on Ameren’s or Ameren Missouri’s results of operations, financial position, and liquidity.

• Ameren’s Merchant Generation segment is expecting 2011 non-fuel other operations and maintenance expenses to be approximately $310 million, which is approximately 10% greater than other operations and maintenance expenses recorded in 2010. Higher employee-related costs are the primary driver for the expected increase.

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• On January 12, 2011, the Illinois governor signed legislation that increased the state’s corporate income tax rate from 7.3% to 9.5%, starting in January 2011. The tax rate is scheduled to decrease to 7.75% in 2015, and it is scheduled to return to 7.3%, in 2025. This corporate income tax rate increase in Illinois is expected to increase Ameren’s income tax expense between $5 to $10 million for all of 2011 (AIC - $3 million to $6 million, Genco - $1 million to $2 million).

• During the week of April 18, 2011, multiple storms, including a tornado on April 22 in metropolitan St. Louis, caused damage to Ameren Missouri’s and Ameren Illinois’s transmission and distribution systems. Ameren Missouri and Ameren Illinois incurred additional capital and operations and maintenance expense associated with these major storms. At this time, Ameren Missouri and Ameren Illinois cannot estimate the storms’ impact on their results of operations, financial position, and liquidity.

• Ameren Missouri, AIC, ATXI and Marketing Company are MISO members. Each member company of MISO is responsible for a portion of MISO’s market cost. FirstEnergy Corp. and Duke Energy Corporation (Ohio and Kentucky) have announced their intention to leave MISO. FirstEnergy Corp. will depart on June 1, 2011, while Duke Energy Corporation (Ohio and Kentucky) will depart on January 1, 2012. Entergy Corporation (and its operating companies) announced plans to join MISO in December 2013, pending regulatory approvals. Ameren will be affected by changes in MISO’s members as the Ameren operating companies’ share of MISO’s market costs will be adjusted to reflect the RTO’s current members. At this time, Ameren is unable to estimate the effects of these MISO member changes on its results of operation, financial position, and liquidity.

• Over the next few years, we expect rising employee benefit costs, higher property taxes, and higher insurance premiums as a result of insurance market conditions and loss experience, among other things.

Other

• Legislation has been introduced in the state of Illinois that would change the ratemaking process and would modernize the electric and natural gas distribution systems. The proposed legislation would apply to electric and natural gas utilities in Illinois on an opt-in basis and would not have any effect on the IPA process for energy procurement. The proposed legislation includes a process for determining rates that would provide for the recovery of actual costs of services that are prudently incurred, reflect the utility’s actual capital structure (excluding goodwill), and include a formula for calculating the return on equity component of the cost of capital. The formula approach would be similar to the process FERC uses for ratemaking. If the proposed legislation were to be enacted in its currently proposed form, AIC would anticipate adopting a formula rate and investing an additional $950 million in capital expenditures over the next ten years to modernize its distribution system. These investments would be incremental to AIC’s average capital expenditures for calendar years 2008 through 2010 and would encourage economic development and job creation within Illinois. However, there can be no assurances that the proposed legislation will be enacted into law.

• 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. Certain of the Ameren subsidiaries are seeking concessions from the labor unions related to certain benefit provisions in light of the current challenging economic environment. Any labor disputes that result in a work stoppage could have a material adverse effect on Ameren’s results of operations, financial position and liquidity.

• In September 2010, President Obama signed into law the Small Business Jobs Act. That legislation includes an extension of the bonus depreciation provision to 2010, retroactive to the beginning of 2010. This provision will allow the Ameren Companies to accelerate depreciation deductions on qualifying property for federal income tax purposes that Ameren would have otherwise received over 15 or 20 years. In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Jobs Creation Act of 2010 was signed into law by President Obama. This provision allowed increased acceleration for qualifying property placed in service after September 8, 2010. Ameren’s preliminary estimate is that these provisions will result in a reduction of Ameren’s 2011 federal income tax payments of between $150 million to $200 million (Ameren Missouri - $105 million to $125 million, AIC - $55 million to $75 million, Genco - $- million to $10 million) and a reduction of Ameren’s 2012 federal income tax payments of between $100 million to $150 million (Ameren Missouri - $75 million to $95 million, AIC - $40 million to $60 million, Genco - $- million to $10 million).

• AIC’s $150 million 6.625% senior secured notes will mature in June 2011. AIC expects to use cash on hand and operating cash flows to repay the maturing notes. Additionally in 2011, AIC is planning to contribute up to an additional $100 million to Ameren’s postretirement benefit plan. This cash contribution will reduce future postretirement expense to the extent expected returns are achieved on the contribution.

• In July 2010, President Obama signed into law the Wall Street Reform and Consumer Protection Act. This law will require additional governmental regulation of derivative and OTC transactions that could significantly expand collateral requirements. The Commodity Futures Trading Commission and the SEC have issued a number of

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proposed rulemakings to implement the new law. Ameren is currently evaluating the new law and the proposed rulemaking to determine their potential impact to our results of operations, financial position, and liquidity. Depending on how the law is ultimately interpreted in subsequent rulemaking, it could reduce the effectiveness of hedging, increasing the volatility of earnings, and could require a significant increase in collateral postings.

• In 2010, President Obama signed into law a health care reform bill that makes several fundamental changes to the U.S. health care system. The Ameren Companies are currently evaluating the long-term effects of this reform and the health care benefits they currently offer their employees and retirees. Additionally, Ameren will continue to monitor and assess the impact of the health care reforms, including any clarifying regulations issued to address how the provisions are to be implemented. Until those reviews are completed, Ameren is unable to estimate the effects of the new law on its results of operations, financial position, and liquidity.

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

REGULATORY MATTERS

See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

Our risk management objective is to optimize our physical generating assets and pursue market opportunities within prudent risk parameters. Our risk management policies are set by a risk management steering committee, which is primarily composed of senior-level Ameren officers.

Except as discussed below, there have been no material changes to the quantitative and qualitative disclosures about market risk in the Form 10-K. See Item 7A under Part II of the Form 10-K for a more detailed discussion of our market risks.

Interest Rate Risk

We are exposed to market risk through changes in interest rates. The following table presents the estimated increase in our annual interest expense and decrease in annual net income that would result if interest rates on variable-rate debt outstanding at March 31, 2011 were to increase by 1%:

	Interest Expense			Net Income(a)
Ameren(b)	$	8		$	(5	)
AMO		2			(1	)
AIC		(c	)		(c	)
Genco		2			(1	)

(a) Calculations are based on an effective tax rate of 40%, 38%, 41% and 41% for Ameren, Ameren Missouri, AIC and Genco, respectively.

(b) Includes intercompany eliminations.

(c) Less than $1 million

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

Credit Risk

Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction. See Note 6 - Derivative Financial Instruments under Part I, Item 1, of this report for information on the potential loss on counterparty exposure as of March 31, 2011.

Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. Our physical and financial instruments are subject to

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credit risk consisting of trade accounts receivables and executory contracts with market risk exposures. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our customer base. At March 31, 2011, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. The risk associated with AIC’s electric and natural gas trade receivables is also mitigated by a rate adjustment mechanism that allows AIC to recover the difference between its actual bad debt expense under GAAP and the bad debt expense included in its base rates. Ameren Missouri and AIC continue to monitor the impact of increasing rates on customer collections. Ameren Missouri and AIC make adjustments to their respective allowance for doubtful accounts as deemed necessary to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.

Ameren, Ameren Missouri, AIC and Genco may have credit exposure associated with off-system or wholesale purchase and sale activity with nonaffiliated companies. At March 31, 2011, Ameren’s, Ameren Missouri’s, AIC’s and Genco’s combined credit exposure to nonaffiliated non-investment-grade trading counterparties was $3 million, net of collateral (2010 - $2 million). We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program. It involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition before we enter into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged lease. We estimate our credit exposure to MISO associated with the MISO Energy and Operating Reserves Market to be $45 million at March 31, 2011 (2010 - $35 million).

Equity Price Risk

Our costs of providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. To the extent the value of plan assets declines, the effect would be reflected in net income and OCI or regulatory assets, and in the amount of cash required to be contributed to the plans.

Commodity Price Risk

We are exposed to changes in market prices for electricity, emission allowances, fuel, and natural gas.

Ameren’s, Ameren Missouri’s and Genco’s risks of changes in prices for power sales are partially hedged through sales agreements. Merchant Generation also seeks to sell power forward to wholesale, municipal, and industrial customers to limit exposure to changing prices. We also attempt to mitigate financial risks through risk management programs and policies, which include forward-hedging programs, and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). However, a portion of the generation capacity of Ameren, Ameren Missouri and Genco is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.

The following table presents how Ameren’s cumulative net income might decrease if power prices were to decrease by 1% on unhedged economic generation for the remaining three quarters of 2011 through 2015:

	Net Income(a)
Ameren(b)	$	(20	)
AMO		(c	)
Genco		(16	)

(a) Calculations are based on an effective tax rate of 40%, 38% and 41% for Ameren, Ameren Missouri and Genco, respectively.

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

(c) Less than $1 million.

Ameren’s forward-hedging power programs include the use of derivative financial swap contracts. These swap contracts financially settle a fixed price against a floating price. The floating price is typically the realized, or settled, price at a liquid regional hub at some forward period of time. Ameren controls the use of derivative financial swap contracts with volumetric and correlation limits that are intended to mitigate any material adverse financial impact. Historically, Ameren has utilized swaps that settle against the Cinergy Hub MISO locational marginal pricing. This hub had traditionally been the most liquid location, with a strong correlation to the pricing that was realized at our generating locations. As of December 31, 2011, MISO intends to stop publishing Cinergy Hub pricing. As a result, Ameren will pursue financial hedging at the next best available regional location with sufficient liquidity. Ameren does not expect any material adverse financial impact to the outcomes of its forward-hedging programs as a result of this change. Ameren will continue to pursue the best available options to fix pricing for the output of its generating units.

Ameren also uses its portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. Due to our physical presence in the market, we are able to identify and pursue opportunities, which can generate additional returns through portfolio management and trading activities. All of this activity is performed within a controlled risk management process. We establish value at risk (VaR) and stop-loss limits that are intended to prevent any negative material financial impact.

We manage risks associated with changing prices of fuel for generation using techniques similar to those used to manage risks associated with changing market prices for electricity.

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Merchant Generation does not have the ability to pass through higher fuel costs to its customers for electric operations with the exception of an immaterial percentage of the output that has been contracted with a fuel cost pass through. Ameren Missouri has a FAC that allows Ameren Missouri to recover, through customer rates, 95% of changes in fuel 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. Ameren Missouri remains exposed to the remaining 5%.

Ameren, Ameren Missouri and Genco have entered into long-term contracts with various suppliers to purchase coal to manage their exposure to fuel prices. The coal hedging strategy is intended to secure a reliable coal supply while reducing exposure to commodity price volatility. Price and volumetric risk mitigation is accomplished primarily through periodic bid procedures, whereby the amount of coal purchased is determined by the current market prices and the minimum and maximum coal purchase guidelines for the given year. Ameren, Ameren Missouri and Genco generally purchase coal up to five years in advance, but they may purchase coal beyond five years to take advantage of favorable deals or market conditions. The strategy also allows for the decision not to purchase coal to avoid unfavorable market conditions. Ameren Missouri 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.

Transportation costs for coal and natural gas can be a significant portion of fuel costs. Ameren, Ameren Missouri and Genco typically hedge coal transportation forward to provide supply certainty and to mitigate transportation price volatility. Natural gas transportation expenses for Ameren’s gas distribution utility companies and the gas-fired generation units of Ameren, Ameren Missouri and Genco are regulated by FERC through approved tariffs governing the rates, terms, and conditions of transportation and storage services. Certain firm transportation and storage capacity agreements held by the Ameren Companies include rights to extend the contracts prior to the termination of the primary term. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariff rates for our requirements.

In addition, coal and coal transportation costs are sensitive to the price of diesel fuel as a result of rail freight fuel surcharges. If diesel fuel costs were to increase or decrease by $0.25 a gallon, Ameren’s fuel expense could increase or decrease by $13 million annually (Ameren Missouri - $8 million, Genco - $4 million). As of March 31, 2011, Ameren had a price cap for 100% of expected fuel surcharges in 2011.

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

With regard to exposure for commodity price risk for nuclear fuel, Ameren Missouri has fixed-priced, base-price-with-escalation, and market-priced agreements. It uses inventories to provide some price hedge to fulfill its Callaway nuclear plant needs for uranium, conversion and enrichment. There is no fuel reloading or planned maintenance outage scheduled for 2012 and 2015. Ameren Missouri has price hedges (including inventories) for approximately 88% of its 2011 to 2014 nuclear fuel requirements.

Nuclear fuel market prices remain subject to an unpredictable supply and demand environment. Ameren Missouri has continued to follow a strategy of managing its inventory of nuclear fuel as an inherent price hedge. New long-term uranium contracts are almost exclusively market-price-related with an escalating price floor. New long-term enrichment contracts usually have a base-price-with-escalation price mechanism, and may also have either a market-price-related component or market-based price re-benchmarking. Ameren Missouri expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected life of the Callaway nuclear plant, at prices that cannot now be accurately predicted. Unlike the electricity and natural gas markets, nuclear fuel markets have somewhat limited financial instruments available for price hedging, so most hedging is done through inventories and forward contracts, if they are available.

With regard to the electric generating operations for Ameren, Ameren Missouri and Genco that are exposed to changes in market prices for natural gas used to run CTs, the natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas while minimizing costs. We optimize transportation and storage options and price risk by structuring supply agreements to maintain access to multiple gas pools and supply basins.

Through the market allocation and auction process, Ameren Missouri, AIC and Genco have been granted FTRs associated with the MISO Energy and Operating Reserves Market. In addition, Marketing Company has acquired FTRs for its participation in the PJM-Northern Illinois market. The

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FTRs are intended to mitigate expected electric transmission congestion charges related to the physical electricity business. Depending on the congestion and prices at various points on the electric transmission grid, FTRs could result in either charges or credits. Complex grid modeling tools are used to determine which FTRs to nominate in the FTR allocation process. There is a risk of incorrectly modeling the amount of FTRs needed, and there is the potential that the FTRs could be ineffective in mitigating transmission congestion charges.

With regard to Ameren Missouri’s and AIC’s electric and natural gas distribution businesses, exposure to changing market prices is in large part mitigated by the fact that there are cost recovery mechanisms in place. These cost recovery mechanisms allow Ameren Missouri and AIC to pass on to retail customers prudently incurred fuel, purchased power and gas supply costs. Ameren Missouri’s and AIC’s strategy is designed to reduce the effect of market fluctuations for our regulated customers. The effects of price volatility cannot be eliminated. However, procurement strategies involve risk management techniques and instruments similar to those outlined earlier, as well as the management of physical assets.

The following table presents, as of March 31, 2011, the percentages of the projected required supply of coal and coal transportation for our coal-fired power plants, nuclear fuel for Ameren Missouri’s Callaway nuclear plant, natural gas for our CTs and retail distribution, as appropriate, and purchased power needs of AIC, which does not own generation, that are price-hedged over the five-year period 2011 through 2015. The projected required supply of these commodities could be significantly affected by changes in our assumptions for such matters as customer demand for our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.

	2011			2012			2013 - 2015
Ameren(a):
Coal		98	%		62	%		13	%
Coal transportation		100			75			28
Nuclear fuel		100			100			82
Natural gas for generation		52			7			-
Natural gas for distribution(b)		49			31			12
Purchased power for AIC(c)		78			56			8
AMO:
Coal		98	%		60	%		17	%
Coal transportation		100			56			38
Nuclear fuel		100			100			82
Natural gas for generation		41			3			-
Natural gas for distribution(b)		39			24			12
AIC:
Natural gas for distribution(b)		51	%		32	%		12	%
Purchased power(c)		78			56			8
Genco:
Coal		98	%		62	%		8	%
Coal transportation		100			100			9
Natural gas for generation		100			-			-

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

(b) Represents the percentage of natural gas price hedged for peak winter season of November through March. The year 2011 represents November 2011 through March 2012. The year 2012 represents November 2012 through March 2013. This continues each successive year through March 2016.

(c) Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of demand. Larger customers are purchasing power from the competitive markets.

The following table shows how our total fuel expense might increase and how our net income might decrease if coal and coal transportation costs were to increase by 1% on any requirements not currently covered by fixed-price contracts for the five-year period 2011 through 2015.

	Coal					Coal Transportation
	Fuel Expense		Net Income (a)			Fuel Expense		Net Income (a)
Ameren(b)(c)	$	10	$	(6	)	$	12	$	(7	)
AMO(c)		1		(d	)		1		(d	)
Genco		7		(4	)		9		(6	)

(a) Calculations are based on an effective tax rate of 40%, 38% and 41% for Ameren, Ameren Missouri, and Genco, respectively.

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

(c) Includes the impact of the FAC.

(d) Less than $1 million.

77

With regard to our exposure for commodity price risk for construction and maintenance activities, Ameren is exposed to changes in market prices for metal commodities and labor availability.

See Note 9 - Commitments and Contingencies under Part I, Item 1 of this report for further information regarding the long-term commitments for the procurement of coal, natural gas, and nuclear fuel.

Fair Value of Contracts

Most of our commodity contracts that meet the definition of derivatives qualify for treatment as NPNS. We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, electricity, uranium, and emission allowances. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three months ended March 31, 2011. We use various methods to determine the fair value of our contracts. In accordance with authoritative guidance for fair value hierarchy levels, our sources used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). All of these contracts have maturities of less than five years. See Note 7 - Fair Value Measurements under Part I, Item 1, of this report for further information regarding the methods used to determine the fair value of these contracts.

Three Months Ended March 31, 2011	Ameren(a)			Nonregistrants			AMO			AIC			Genco
Fair value of contracts at beginning of period, net	$	(79	)	$	384		$	11		$	(493	)	$	19
Contracts realized or otherwise settled during the period		18			(45	)		(4	)		70			(3	)
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-
Fair value of new contracts entered into during the period		(3	)		(6	)		-			3			-
Other changes in fair value		57			28			33			(18	)		14
Fair value of contracts outstanding at end of period, net	$	(7	)	$	361		$	40		$	(438	)	$	30

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

The following table presents maturities of derivative contracts as of March 31, 2011, based on the hierarchy levels used to determine the fair value of the contracts:

Sources of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years			Maturity in Excess of 5 Years		Total Fair Value
Ameren:
Level 1	$	(9	)	$	(6	)	$	(1	)	$	-	$	(16	)
Level 2(a)		1			-			-			-		1
Level 3(b)		19			(10	)		(1	)		-		8
Total	$	11		$	(16	)	$	(2	)	$	-	$	(7	)
AMO:
Level 1	$	(4	)	$	(4	)	$	(1	)	$	-	$	(9	)
Level 2(a)		1			-			-			-		1
Level 3(b)		31			18			(1	)		-		48
Total	$	28		$	14		$	(2	)	$	-	$	40
AIC:
Level 1	$	(3	)	$	(2	)	$	-		$	-	$	(5	)
Level 2(a)		-			-			-			-		-
Level 3(b)		(240	)		(192	)		(1	)		-		(433	)
Total	$	(243	)	$	(194	)	$	(1	)	$	-	$	(438	)
Genco:
Level 1	$	(2	)	$	-		$	-		$	-	$	(2	)
Level 2(a)		-			-			-			-		-
Level 3(b)		22			10			-			-		32
Total	$	20		$	10		$	-		$	-	$	30

(a) Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed-price vs. floating over-the-counter natural gas swaps.

(b) Principally power forward contract values based on a Black-Scholes model that includes information from external sources and our estimates. Level 3 also includes option contract values based on our estimates.

78

ITEM 4. CONTROLS AND PROCEDURES.

(a) Evaluation of Disclosure Controls and Procedures

As of March 31, 2011, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.

(b) Change in Internal Controls

There has been no change in any of the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, each of their internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. 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. Material legal and administrative proceedings discussed in Note 2 - Rate and Regulatory Matters, Note 9 - Commitments and Contingencies, and Note 10 - Callaway Nuclear Plant under Part I, Item 1, of this report or Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K 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 Ameren Missouri pending before the MoPSC;

• the MoPSC’s FAC prudence review and future appeals;

• 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 Ameren Missouri 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 Ameren Missouri’s Taum Sauk pumped-storage hydroelectric facility;

• asbestos-related litigation associated with Ameren, Ameren Missouri, AIC and Genco; and

• litigation associated with the DOE’s contractual obligation for spent nuclear fuel.

ITEM 1A. RISK FACTORS.

There have been no material changes to the risk factors disclosed in Part I, Item 1A, Risk Factors in the Form 10-K.

79

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

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
January 1 - January 31, 2011		69,466	$	28.84	-	-
February 1 - February 28, 2011		50,340		27.72	-	-
March 1 - March 31, 2011		403		27.09	-	-
Total		120,209	$	28.36	-	-

(a) Included in January were 19,663 shares of Ameren common stock purchased by Ameren in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligations for Ameren board of directors’ compensation awards. The remaining 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. Included in February were 22,523 shares of Ameren common stock purchased by Ameren from employee participants to satisfy participants’ tax obligations incurred by the release of restricted shares of Ameren common stock under Ameren’s Long-term Incentive Plan of 1998.The remaining shares of Ameren common stock in February and March 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
January 1 - January 31, 2011		-	$	-	-	-
February 1 - February 28, 2011		-		-	-	-
March 1 - March 31, 2011		16		74.24	-	-
Total		16	$	74.24	-	-

(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.

Ameren Missouri and Genco did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from January 1, 2011, to March 31, 2011.

80

ITEM 6. EXHIBITS.

The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.

Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
Articles of Incorporation/By-Laws
3.1(i)	Ameren	Restated Articles of Incorporation of Ameren	Annex F to Part I of the Registration Statement on Form S-4, File No. 33-64165
3.2(i)	Ameren	Certificate of Amendment to Ameren’s Restated Articles of Incorporation filed December 14, 1997	1998 Form 10-K, Exhibit 3(i), File No. 1-14756
3.3(i)	Ameren	Certificate of Amendment to Ameren’s Restated Articles of Incorporation filed April 21, 2011	April 21, 2011 Form 8-K, Exhibit 3(i), File No. 1-14756
Material Contracts
10.1	Ameren	*Performance Stock Bonus Award Agreement, dated March 1, 2011, between Ameren and Adam C. Heflin
Statement re: Computation of Ratios
12.1	Ameren	Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.2	Ameren Missouri	Ameren Missouri’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.3	AIC	AIC’s’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.4	Genco	Genco’s Statement of Computation of Ratio of Earnings to Fixed Charges
Rule 13a-14(a) / 15d-14(a) Certifications
31.1	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren
31.2	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren
31.3	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Missouri
31.4	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Missouri
31.5	AIC	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of AIC
31.6	AIC	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of AIC
31.7	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco
31.8	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Genco
Section 1350 Certifications
32.1	Ameren	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren

81

Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
32.2	Ameren Missouri	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri
32.3	AIC	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of AIC
32.4	Genco	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco
XBRL - Related Documents
101.INS**	Ameren	XBRL Instance Document
101.SCH**	Ameren	XBRL Taxonomy Extension Schema Document
101.CAL**	Ameren	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**	Ameren	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	Ameren	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF**	Ameren	XBRL Taxonomy Extension Definition Document

* Compensatory plan or arrangement.

** Attached as Exhibit 101 to this report is the following financial information from Ameren’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statement of Income for the three months ended March 31, 2011 and 2010, (ii) the Consolidated Balance Sheet at March 31, 2011, and December 31, 2010, (iii) the Consolidated Statement of Cash Flows for the three months ended March 31, 2011 and 2010, and (iv) the Combined Notes to the Financial Statements for the three months ended March 31, 2011. These Exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.

Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above that such registrant has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.

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SIGNATURES

Pursuant to the requirements of the Exchange Act, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.

AMEREN CORPORATION

(Registrant)

/s/ Martin J. Lyons, Jr.

     Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

UNION ELECTRIC COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

     Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

AMEREN ILLINOIS COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

     Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

AMEREN ENERGY GENERATING COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

     Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

Date: May 10, 2011

83

EX-10.1

Exhibit 10.1

Performance Stock Bonus

Award Agreement

Ameren Corporation

2006 Omnibus Incentive Compensation Plan

March 1, 2011

Ameren Corporation

Performance Stock Bonus Award Agreement

THIS AGREEMENT, effective March 1, 2011, (“Effective Date”) represents the grant of a Performance Stock Bonus (“Award”) by Ameren Corporation (the “Company”) to the Participant named below, pursuant to the provisions of the Ameren Corporation 2006 Omnibus Incentive Compensation Plan (the “Plan”). The number of Shares ultimately paid, if any, with respect to the Performance Stock Bonus shall be determined pursuant to Section 3 of this Agreement.

The Plan provides a description of the terms and conditions governing the Performance Stock Bonus. If there is any inconsistency between the terms of this Agreement and the terms of the Plan, the Plan’s terms will completely supersede and replace the conflicting terms of this Agreement. All capitalized terms will have the meanings ascribed to them in the Plan, unless specifically set forth otherwise herein. The parties hereto agree as follows:

1. Grant Information. The individual named below has been selected to be a Participant in the Plan and is hereby granted the following Performance Stock Bonus, as specified below:

(a) Participant: Adam C. Heflin.

(b) Target Value of Performance Stock Bonus: The Participant’s annual base salary for 2011 as in effect on the Effective Date.

2. Determination Date. As more fully described in Section 4, the amount of the Performance Stock Bonus, if any, shall be determined as of the third anniversary of the Effective Date (“Determination Date”).

3. Settlement. Provided this Award has not been forfeited as described in Section 6, and subject to the provisions of Section 6 relating to pro-ration, if applicable, the Company shall transfer to the Participant a number of Shares determined by multiplying the Target Value of the Performance Stock Bonus by a percentage factor (“Performance Factor”) determined as of the Determination Date in accordance with Section 4, and dividing such product by the Fair Market Value of one Share on the Determination Date (or if such date is not a business day, on the next succeeding business day). Any fractional Shares resulting from the application of this Section 3 shall be disregarded. The share transfer described above shall be made within 30 days after the Human Resources Committee makes the determination of the amount of the Performance Stock Bonus as described in Section 4.

4. Performance Factor. The Human Resources Committee shall make the determination of the amount of the Performance Stock Bonus, if any, no later than the June 30 following the Determination Date. If the Callaway Nuclear Facility remains at an overall plant performance level consistent with its performance on the Effective Date during the period beginning on the Effective Date and ending on the Determination Date (“Performance Period”), the Performance Factor as of the Determination Date shall be 100%. If the overall Callaway Nuclear Facility performance during the Performance Period is less than or greater than such facility’s performance as of the Effective Date, the Human Resources Committee of the Company’s Board of Directors shall assign a Performance Factor as of the Determination Date reflecting such performance. Such Performance

Factor may be any percentage between 0% and 150%. The Callaway Nuclear Facility’s overall performance during the Performance Period and the Performance Factor shall be determined by the Human Resources Committee in its sole and absolute discretion.

5. Right as Shareholder. The Participant shall have no voting or any other rights as a shareholder of the Company with respect to any Shares payable in accordance with this Agreement prior to the date such Shares are transferred to the Participant. The Participant will obtain full voting and other rights as a shareholder of the Company upon the transfer of Shares as provided in Section 3 of this Agreement. For the avoidance of doubt, dividends will not accrue on the Award prior to the date the Shares are transferred.

6. Termination of Employment. Except as provided in this Section, if the Participant’s employment with the Company terminates for any reason prior to the Determination Date, the Participant shall forfeit his rights to receive a Performance Stock Bonus, and shall receive no Shares in connection with this Agreement. Notwithstanding the foregoing, (a) in the event of the Participant’s termination of employment prior to the Determination Date under circumstances which entitle him to receive separation benefits under Section 4.1 of the Second Amended and Restated Ameren Corporation Change of Control Severance Plan, as amended, the Participant shall be entitled to a Performance Stock Bonus hereunder to the full extent that he would have been so entitled if he had continued employment until the Determination Date, and (b) in the event of the Participant’s death or disability which entitles him to benefits under a long-term disability plan maintained by the Company, or involuntary termination of employment without Cause (as defined in the Second Amended and Restated Ameren Corporation Change of Control Severance Plan) prior to the Determination Date, the Participant shall be entitled to receive a Performance Stock Bonus based on the bonus he would have received if he had continued employment until the Determination Date, but pro-rated based on the number of completed days in the Performance Period prior to such death, disability, or involuntary termination of employment without Cause.

7. Nontransferability. The Participant shall have no right to sell, transfer, pledge, assign or otherwise alienate or hypothecate (a “Transfer”) his rights under this Agreement or amounts payable in connection with this Agreement other than by will or by the laws of descent and distribution, except as provided in the Plan. If any Transfer, whether voluntary or involuntary, of the Participant’s rights under this Agreement is made (other than as permitted in the previous sentence), or if any attachment, execution, garnishment, or lien will be issued against or placed upon any amounts payable with respect to this Agreement, the Participant’s rights under this Agreement and rights to amounts payable hereunder will be immediately forfeited to the Company, and this Agreement shall lapse and terminate.

8. Requirements of Law. The grant of the Performance Stock Bonus or Shares under the Plan and this Agreement is subject to all applicable laws, rules, and regulations, and conditioned upon such approvals by any governmental agencies or national securities exchanges as may be required.

9. Tax Withholding. The Company will have the power and the right to deduct or withhold, or require the Participant to remit to the Company, an amount sufficient to satisfy federal, state, and local taxes, domestic or foreign, required by law or regulation to be withheld with respect to any taxable event arising as a result of this Agreement.

10. Stock Withholding. With respect to withholding required upon any taxable event arising as a result of the Performance Stock Bonus granted or Shares transferred hereunder, the Company, unless otherwise notified by the Participant in writing within thirty (30) days prior to such taxable event, will satisfy the tax withholding requirement by withholding Shares having a Fair Market Value equal to the amount required to be withheld to satisfy federal, state, and local withholding requirements. The Participant agrees to pay to the Company, its Affiliates, and/or its Subsidiaries any amount of tax that the Company, its Affiliates, and/or its Subsidiaries may be required to withhold as a result of the Participant’s participation in the Plan that cannot be satisfied by the means previously described.

11. Administration. This Agreement and the Participant’s rights hereunder are subject to all the terms and conditions of the Plan, as the same may be amended from time to time, as well as to such rules and regulations as the Human Resources Committee may adopt for administration of the Plan. It is expressly understood that the Human Resources Committee is authorized to administer, construe, and make all determinations necessary or appropriate to the administration of the Plan and this Agreement, all of which will be binding upon the Participant.

12. Continuation of Employment. This Agreement does not confer upon the Participant any right to continuation of employment by the Company, its Affiliates, and/or its Subsidiaries, nor will this Agreement interfere in any way with the Company’s, its Affiliates’, and/or its Subsidiaries’ right to terminate the Participant’s employment.

13. Amendment to the Plan. The Plan is discretionary in nature and the Human Resources Committee may terminate, amend, or modify the Plan; provided, however, that no such termination, amendment, or modification of the Plan may in any way adversely affect the Participant’s rights under this Agreement without the Participant’s written approval.

14. Amendment to this Agreement. The Company may amend this Agreement in any manner, provided that no such amendment may adversely affect the Participant’s rights hereunder without the Participant’s written approval.

15. Successor. All obligations of the Company under the Plan and this Agreement with respect to the Performance Stock Bonus will be binding on any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation, or otherwise, of all or substantially all of the business and/or assets of the Company.

16. Severability. The provisions of this Agreement are severable and if any one or more provisions are determined to be illegal or otherwise unenforceable, in whole or in part, the remaining provisions will nevertheless be binding and enforceable.

17. Applicable Laws and Consent to Jurisdiction. The validity, construction, interpretation, and enforceability of this Agreement will be determined and governed by the laws of the State of Missouri without giving effect to the principles of conflicts of law. For the purpose of litigating any dispute that arises under this Agreement, the parties hereby consent to exclusive jurisdiction and agree that such litigation will be conducted in the federal or state courts of the State of Missouri.

IN WITNESS WHEREOF, the parties have caused this Agreement to be executed effective as of February 10, 2011.

Ameren Corporation
By:	/s/ Mark C. Lindgren
By:	/s/ Adam C. Heflin
	Adam C. Heflin

EX-12.1

Exhibit 12.1

Ameren Corporation

Computation of Ratio of Earnings to Fixed Charges

(Thousands of Dollars, Except Ratios)

	Three Months Ended March 31, 2011		Year Ended December 31, 2010 (a)
Net income from continuing operations attributable to Ameren Corporation	$	70,941	$	138,678
Add- Net income attributable to noncontrolling interest		1,242		3,366
Add- Taxes based on income		45,126		325,320
Net income before income taxes and noncontrolling interests		117,309		467,364
Add- fixed charges:
Interest on short-term and long-term debt (b)		123,694		511,468
Estimated interest cost within rental expense		1,918		8,593
Amortization of net debt premium, discount, and expenses		3,400		14,337
Subsidiary preferred stock dividends		1,611		8,278
Adjust preferred stock dividends to pretax basis		1,002		4,753
Total fixed charges		131,625		547,429
Less: Adjustment of preferred stock dividends to pretax basis		1,002		4,753
Earnings available for fixed charges	$	247,932	$	1,010,040
Ratio of earnings to fixed charges		1.88		1.84

^(a)  In the third quarter of 2010, Ameren Corporation recorded a goodwill and other impairment charge of $589 million. See Note 17 - Goodwill and Other Asset Impairments of the 2010 Form 10-K for additional information.

^(b)  Includes interest expense related to uncertain tax positions

EX-12.2

Exhibit 12.2

Union Electric Company

Computation of Ratio of Earnings to Fixed Charges and Combined

Fixed Charges and Preferred Stock Dividend Requirements

(Thousands of Dollars, Except Ratios)

	Three Months Ended March 31, 2011		Year Ended December 31, 2010
Net income from continuing operations	$	21,456	$	368,702
Add- Taxes based on income		11,529		199,085
Net income before income taxes		32,985		567,787
Add- fixed charges:
Interest on short-term and long-term debt (a)		59,431		232,157
Estimated interest cost within rental expense		766		3,689
Amortization of net debt premium, discount, and expenses		1,636		6,744
Total fixed charges		61,833		242,590
Earnings available for fixed charges		94,818		810,377
Ratio of earnings to fixed charges		1.53		3.34
Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends		855		4,716
Adjustment to pretax basis		459		2,546
		1,314		7,262
Combined fixed charges and preferred stock dividend requirements	$	63,147	$	249,852
Ratio of earnings to combined fixed charges and preferred stock dividend requirements		1.50		3.24

^(a)  Includes interest expense related to uncertain tax positions

EX-12.3

Exhibit 12.3

Ameren Illinois Company

Computation of Ratio of Earnings to Fixed Charges and Combined

Fixed Charges and Preferred Stock Dividend Requirements

(Thousands of Dollars, Except Ratios)

	Three Months Ended March 31, 2011		Year Ended December 31, 2010
Net income from continuing operations	$	33,350	$	212,547
Add- Taxes based on income		19,814		136,614
Net income before income taxes		53,164		349,161
Add- fixed charges:
Interest on short-term and long-term debt (a)		34,214		152,667
Estimated interest cost within rental expense		893		3,899
Amortization of net debt premium, discount, and expenses		1,330		5,250
Total fixed charges		36,437		161,816
Earnings available for fixed charges		89,601		510,977
Ratio of earnings to fixed charges		2.46		3.15
Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends		756		4,435
Adjustment to pretax basis		449		2,396
		1,205		6,831
Combined fixed charges and preferred stock dividend requirements	$	37,642	$	168,647
Ratio of earnings to combined fixed charges and preferred stock dividend requirements		2.38		3.02

^(a)  Includes interest expense related to uncertain tax positions

EX-12.4

Exhibit 12.4

Ameren Energy Generating Company

Computation of Ratio of Earnings to Fixed Charges

(Thousands of Dollars, Except Ratios)

	Three Months Ended March 31, 2011		Year Ended December 31, 2010
Net income (loss) from continuing operations attributable to Ameren Energy Generating Company	$	21,010	$	(38,573	)
Add- Net income attributable to noncontrolling interest		1,242		3,366
Add- Taxes based on income		15,775		19,422
Net income (loss) before income taxes and noncontrolling interest		38,027		(15,785	)
Add- fixed charges:
Interest on short-term and long-term debt (a)		16,422		76,321
Estimated interest cost within rental expense		72		295
Amortization of net debt premium, discount, and expenses		169		1,026
Total fixed charges		16,663		77,642
Earnings available for fixed charges	$	54,690	$	61,857
Ratio of earnings to fixed charges		3.28		-	(b)

^(a)  Includes interest expense related to uncertain tax positions

^(b)  Earnings are inadequate to cover fixed charges by $15.8 million for the year ended December 31, 2010. In the third quarter of 2010, Ameren Energy Generating Company recorded a goodwill and other impairment charge of $170 million. See
Note 17 - Goodwill and Other Asset Impairments of the 2010 Form 10-K for additional information.

EX-31.1

Exhibit 31.1

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL EXECUTIVE OFFICER OF AMEREN CORPORATION

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Thomas R. Voss, certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2011 of Ameren Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 10, 2011

/s/ Thomas R. Voss

Thomas R. Voss

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL FINANCIAL OFFICER OF AMEREN CORPORATION

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Martin J. Lyons, Jr., certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2011 of Ameren Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 10, 2011

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-31.3

Exhibit 31.3

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL EXECUTIVE OFFICER OF UNION ELECTRIC COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Warner L. Baxter, certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2011 of Union Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 10, 2011

/s/ Warner L. Baxter

Warner L. Baxter

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

EX-31.4

Exhibit 31.4

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL FINANCIAL OFFICER OF UNION ELECTRIC COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Martin J. Lyons, Jr., certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2011 of Union Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 10, 2011

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-31.5

Exhibit 31.5

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL EXECUTIVE OFFICER OF AMEREN ILLINOIS COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Scott A. Cisel, certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2011 of Ameren Illinois Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 10, 2011

/s/ Scott A. Cisel

Scott A. Cisel

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

EX-31.6

Exhibit 31.6

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL FINANCIAL OFFICER OF AMEREN ILLINOIS COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Martin J. Lyons, Jr., certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2011 of Ameren Illinois Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 10, 2011

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-31.7

Exhibit 31.7

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL EXECUTIVE OFFICER OF

AMEREN ENERGY GENERATING COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Steven R. Sullivan, certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2011 of Ameren Energy Generating Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 10, 2011

/s/ Steven R. Sullivan

Steven R. Sullivan

Chairman and President

(Principal Executive Officer)

EX-31.8

Exhibit 31.8

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL FINANCIAL OFFICER OF AMEREN ENERGY GENERATING COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Martin J. Lyons, Jr., certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2011 of Ameren Energy Generating Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 10, 2011

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.1

Exhibit 32.1

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

AMEREN CORPORATION

(required by Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-Q for the quarterly period ended March 31, 2011 of Ameren Corporation (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: May 10, 2011

/s/ Thomas R. Voss

Thomas R. Voss

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.2

Exhibit 32.2

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

UNION ELECTRIC COMPANY

(required by Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-Q for the quarterly period ended March 31, 2011 of Union Electric Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: May 10, 2011

/s/ Warner L. Baxter

Warner L. Baxter

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.3

Exhibit 32.3

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

AMEREN ILLINOIS COMPANY

(required by Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-Q for the quarterly period ended March 31, 2011 of Ameren Illinois Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: May 10, 2011

/s/ Scott A. Cisel

Scott A. Cisel

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.4

Exhibit 32.4

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

AMEREN ENERGY GENERATING COMPANY

(required by Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-Q for the quarterly period ended March 31, 2011 of Ameren Energy Generating Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: May 10, 2011

/s/ Steven R. Sullivan

Steven R. Sullivan

Chairman and President

(Principal Executive Officer)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)