Ameren Illinois (AILIN) 10-Q 2011 Q2 Quarterly report

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 June 30, 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	x	No	¨
Ameren Illinois Company	Yes	x	No	¨
Ameren Energy Generating Company	Yes	x	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 July 29, 2011, was as follows:

Ameren Corporation	Common stock, $0.01 par value per share - 241,666,357
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		59
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		86
Item 4.	Controls and Procedures		90
PART II	Other Information
Item 1.	Legal Proceedings		91
Item 1A.	Risk Factors		91
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		91
Item 6.	Exhibits		92
Signatures			95

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 beginning 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.

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GLOSSARY OF TERMS AND ABBREVIATIONS

We use the words “our,” “we” or “us” with respect to certain information that relates to 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 Illinois or AIC - Ameren Illinois Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois, doing business as Ameren Illinois. This business consists of the combined rate-regulated electric and natural gas transmission and distribution businesses operated by CIPS, CILCO and IP before the Ameren Illinois Merger. References to Ameren Illinois prior to the Ameren Illinois Merger refer collectively to the rate-regulated electric and natural gas transmission and distribution businesses of CIPS, CILCO and IP. Immediately after the Ameren Illinois Merger, Ameren Illinois distributed the common stock of AERG to Ameren Corporation. AERG’s operating results and cash flows were presented as discontinued operations in Ameren Illinois’ financial statements.

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

Ameren Illinois Regulated Segment-A financial reporting segment consisting of Ameren Illinois’ rate-regulated businesses.

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 only of Union Electric Company’s rate-regulated businesses.

CCR - Coal combustion residuals.

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

CSAPR - Cross-State Air Pollution Rule.

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 Illinois electric and natural gas rate proceedings; the court appeals related to Ameren Missouri’s 2009, 2010, and 2011 electric rate orders, Ameren Illinois’ 2010 electric and natural gas rate order, and Ameren Missouri’s FAC prudence review; 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;

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

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

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

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

• our assessment of our liquidity;

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

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

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

• the impact of system outages;

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

• the extent to which Ameren Missouri prevails in its claims against insurers in connection with its Taum Sauk pumped-storage hydroelectric energy center incident;

• the extent to which Ameren Missouri is permitted by its regulators to recover in rates investments made in connection with a proposed second unit at its Callaway energy center;

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

• operation of Ameren Missouri’s Callaway energy center, including planned and unplanned outages, decommissioning costs and potential increased costs as a result of nuclear-related developments in Japan in 2011;

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

• the impact of current environmental regulations on utilities and power generating companies and the expectation that more stringent requirements, including those related to greenhouse gases, other emissions, and energy efficiency, will be enacted over time, which could limit or terminate the operation of certain of our generating units, increase our costs, result in an impairment of our assets, reduce our customers’ demand for electricity or natural gas, or otherwise have a negative financial effect;

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

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

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

• the cost and availability of transmission capacity for the energy generated by the Ameren Companies’ energy centers 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.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF INCOME

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Operating Revenues:
Electric	$	1,614	$	1,552	$	3,084	$	3,007
Gas		167		173		601		658
Total operating revenues		1,781		1,725		3,685		3,665
Operating Expenses:
Fuel		371		286		750		579
Purchased power		237		268		464		539
Gas purchased for resale		79		83		367		416
Other operations and maintenance		475		465		938		902
Depreciation and amortization		194		190		389		377
Taxes other than income taxes		109		102		234		223
Total operating expenses		1,465		1,394		3,142		3,036
Operating Income		316		331		543		629
Other Income and Expenses:
Miscellaneous income		17		24		33		46
Miscellaneous expense		5		2		10		9
Total other income		12		22		23		37
Interest Charges		104		115		223		247
Income Before Income Taxes		224		238		343		419
Income Taxes		85		83		130		158
Net Income		139		155		213		261
Less: Net Income Attributable to Noncontrolling Interests		1		3		4		7
Net Income Attributable to Ameren Corporation	$	138	$	152	$	209	$	254
Earnings per Common Share – Basic and Diluted	$	0.57	$	0.64	$	0.87	$	1.07
Dividends per Common Share	$	0.385	$	0.385	$	0.77	$	0.77
Average Common Shares Outstanding		241.2		238.4		240.9		238.0

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)

	June  30, 2011		December  31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	378	$	545
Accounts receivable – trade (less allowance for doubtful accounts of $25 and $23, respectively)		507		500
Unbilled revenue		368		406
Miscellaneous accounts and notes receivable		249		231
Materials and supplies		654		707
Mark-to-market derivative assets		159		129
Current regulatory assets		184		267
Other current assets		104		109
Total current assets		2,603		2,894
Property and Plant, Net		17,945		17,853
Investments and Other Assets:
Nuclear decommissioning trust fund		356		337
Goodwill		411		411
Intangible assets		4		7
Regulatory assets		1,224		1,263
Other assets		848		750
Total investments and other assets		2,843		2,768
TOTAL ASSETS	$	23,391	$	23,515
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	5	$	155
Short-term debt		337		269
Accounts and wages payable		482		651
Taxes accrued		139		63
Interest accrued		107		107
Customer deposits		100		100
Mark-to-market derivative liabilities		135		161
Current regulatory liabilities		160		99
Other current liabilities		262		283
Total current liabilities		1,727		1,888
Credit Facility Borrowings		200		460
Long-term Debt, Net		6,854		6,853
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		3,121		2,886
Accumulated deferred investment tax credits		87		90
Regulatory liabilities		1,424		1,319
Asset retirement obligations		487		475
Pension and other postretirement benefits		1,067		1,045
Other deferred credits and liabilities		481		615
Total deferred credits and other liabilities		6,667		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 241.6 and 240.4, respectively		2		2
Other paid-in capital, principally premium on common stock		5,559		5,520
Retained earnings		2,248		2,225
Accumulated other comprehensive loss		(21)		(17)
Total Ameren Corporation stockholders’ equity		7,788		7,730
Noncontrolling Interests		155		154
Total equity		7,943		7,884
TOTAL LIABILITIES AND EQUITY	$	23,391	$	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)

	Six Months Ended June 30,
	2011		2010
Cash Flows From Operating Activities:
Net income	$	213	$	261
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sales of properties		(11)		(5)
Net mark-to-market gain on derivatives		(5)		-
Depreciation and amortization		391		387
Amortization of nuclear fuel		34		19
Amortization of debt issuance costs and premium/discounts		12		12
Deferred income taxes and investment tax credits, net		221		175
Allowance for equity funds used during construction		(15)		(26)
Other		10		5
Changes in assets and liabilities:
Receivables		(55)		(36)
Materials and supplies		55		108
Accounts and wages payable		(133)		(125)
Taxes accrued		76		75
Assets, other		60		(99)
Liabilities, other		(3)		-
Pension and other postretirement benefits		31		33
Counterparty collateral, net		23		(69)
Taum Sauk insurance recoveries, net of costs		(1)		56
Net cash provided by operating activities		903		771
Cash Flows From Investing Activities:
Capital expenditures		(507)		(547)
Nuclear fuel expenditures		(33)		(22)
Purchases of securities – nuclear decommissioning trust fund		(125)		(118)
Sales of securities – nuclear decommissioning trust fund		113		110
Proceeds from sales of properties		49		20
Other		5		(3)
Net cash used in investing activities		(498)		(560)
Cash Flows From Financing Activities:
Dividends on common stock		(186)		(183)
Dividends paid to noncontrolling interest holders		(3)		(5)
Short-term and credit facility repayments, net		(192)		(160)
Maturities of long-term debt		(150)		-
Issuances of common stock		32		43
Generator advances for construction refunded, net of receipts		(73)		(22)
Net cash used in financing activities		(572)		(327)
Net change in cash and cash equivalents		(167)		(116)
Cash and cash equivalents at beginning of year		545		622
Cash and cash equivalents at end of period	$	378	$	506
Noncash investing activity – DOE Settlement (Note 10)	$	9	$	-

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

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UNION ELECTRIC COMPANY

STATEMENT OF INCOME

(Unaudited) (In millions)

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Operating Revenues:
Electric	$	791	$	737	$	1,493	$	1,344
Gas		28		23		97		98
Other		3		1		4		1
Total operating revenues		822		761		1,594		1,443
Operating Expenses:
Fuel		204		112		433		236
Purchased power		26		42		46		86
Gas purchased for resale		11		10		51		56
Other operations and maintenance		231		240		464		458
Depreciation and amortization		98		92		198		184
Taxes other than income taxes		76		68		149		136
Total operating expenses		646		564		1,341		1,156
Operating Income		176		197		253		287
Other Income and Expenses:
Miscellaneous income		16		20		29		41
Miscellaneous expense		3		1		6		3
Total other income		13		19		23		38
Interest Charges		45		43		99		102
Income Before Income Taxes		144		173		177		223
Income Taxes		53		58		64		80
Net Income		91		115		113		143
Preferred Stock Dividends		1		2		2		3
Net Income Available to Common Stockholder	$	90	$	113	$	111	$	140

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

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UNION ELECTRIC COMPANY

BALANCE SHEET

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

	June 30, 2011		December 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	79	$	202
Accounts receivable – trade (less allowance for doubtful accounts of $8 and $8, respectively)		236		217
Accounts receivable – affiliates		10		6
Unbilled revenue		200		159
Miscellaneous accounts and notes receivable		71		116
Materials and supplies		343		341
Mark-to-market derivative assets		58		35
Current regulatory assets		114		179
Other current assets		14		20
Total current assets		1,125		1,275
Property and Plant, Net		9,862		9,775
Investments and Other Assets:
Nuclear decommissioning trust fund		356		337
Intangible assets		4		2
Regulatory assets		691		694
Other assets		489		421
Total investments and other assets		1,540		1,454
TOTAL ASSETS	$	12,527	$	12,504
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	5	$	5
Accounts and wages payable		179		326
Accounts payable – affiliates		55		75
Taxes accrued		134		76
Interest accrued		73		63
Current regulatory liabilities		70		23
Current accumulated deferred income taxes, net		18		43
Other current liabilities		90		89
Total current liabilities		624		700
Long-term Debt, Net		3,949		3,949
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		2,027		1,908
Accumulated deferred investment tax credits		76		78
Regulatory liabilities		801		766
Asset retirement obligations		373		363
Pension and other postretirement benefits		371		369
Other deferred credits and liabilities		176		218
Total deferred credits and other liabilities		3,824		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		1,984		2,007
Total stockholders’ equity		4,130		4,153
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	12,527	$	12,504

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

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UNION ELECTRIC COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Six Months Ended June 30,
	2011		2010
Cash Flows From Operating Activities:
Net income	$	113	$	143
Adjustments to reconcile net income to net cash provided by operating activities:
Net mark-to-market loss on derivatives		1		-
Depreciation and amortization		198		184
Amortization of nuclear fuel		34		19
Amortization of debt issuance costs and premium/discounts		3		-
Deferred income taxes and investment tax credits, net		86		106
Allowance for equity funds used during construction		(14)		(25)
Other		-		(2)
Changes in assets and liabilities:
Receivables		(82)		(97)
Materials and supplies		(2)		22
Accounts and wages payable		(136)		(158)
Taxes accrued		58		125
Assets, other		57		(137)
Liabilities, other		23		39
Pension and other postretirement benefits		15		12
Taum Sauk costs, net of insurance recoveries		(1)		56
Net cash provided by operating activities		353		287
Cash Flows From Investing Activities:
Capital expenditures		(272)		(321)
Nuclear fuel expenditures		(33)		(22)
Purchases of securities – nuclear decommissioning trust fund		(125)		(118)
Sales of securities – nuclear decommissioning trust fund		113		110
Other		(3)		-
Net cash used in investing activities		(320)		(351)
Cash Flows From Financing Activities:
Dividends on common stock		(135)		(116)
Dividends on preferred stock		(2)		(3)
Generator advances for construction received (refunded)		(19)		7
Net cash used in financing activities		(156)		(112)
Net change in cash and cash equivalents		(123)		(176)
Cash and cash equivalents at beginning of year		202		267
Cash and cash equivalents at end of period	$	79	$	91
Noncash investing activity – DOE Settlement (Note 10)	$	9	$	-

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

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AMEREN ILLINOIS COMPANY

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions)

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010(a)		2011		2010(a)
Operating Revenues:
Electric	$	483	$	497	$	925	$	998
Gas		139		150		505		560
Other		1		-		1		-
Total operating revenues		623		647		1,431		1,558
Operating Expenses:
Purchased power		196		227		407		496
Gas purchased for resale		67		73		315		359
Other operations and maintenance		181		159		349		321
Depreciation and amortization		54		52		106		106
Taxes other than income taxes		26		24		67		66
Total operating expenses		524		535		1,244		1,348
Operating Income		99		112		187		210
Other Income and Expenses:
Miscellaneous income		1		2		3		4
Miscellaneous expense		1		1		2		4
Total other income		-		1		1		-
Interest Charges		35		34		70		71
Income Before Income Taxes		64		79		118		139
Income Taxes		26		31		46		55
Income from Continuing Operations		38		48		72		84
Income from Discontinued Operations, net of tax		-		9		-		21
Net Income		38		57		72		105
Preferred Stock Dividends		1		2		2		3
Net Income Available to Common Stockholder	$	37	$	55	$	70	$	102

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

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

11

AMEREN ILLINOIS COMPANY

BALANCE SHEET

(Unaudited) (In millions)

	June 30,     2011		December  31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	253	$	322
Accounts receivable – trade (less allowance for doubtfulaccounts of $16 and $13, respectively)		197		230
Accounts receivable – affiliates		21		73
Unbilled revenue		129		205
Miscellaneous accounts and notes receivable		104		44
Materials and supplies		145		198
Current regulatory assets		243		260
Other current assets		109		106
Total current assets		1,201		1,438
Property and Plant, Net		4,657		4,576
Investments and Other Assets:
Tax receivable – Genco		64		72
Goodwill		411		411
Regulatory assets		628		747
Other assets		193		162
Total investments and other assets		1,296		1,392
TOTAL ASSETS	$	7,154	$	7,406
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	-	$	150
Accounts and wages payable		185		182
Accounts payable – affiliates		65		82
Taxes accrued		47		26
Customer deposits		82		83
Mark-to-market derivative liabilities		64		82
Mark-to-market derivative liabilities – affiliates		173		172
Environmental remediation		55		72
Current regulatory liabilities		90		76
Other current liabilities		77		90
Total current liabilities		838		1,015
Long-term Debt, Net		1,658		1,657
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		807		724
Accumulated deferred investment tax credits		7		8
Regulatory liabilities		623		553
Pension and other postretirement benefits		446		413
Other deferred credits and liabilities		282		460
Total deferred credits and other liabilities		2,165		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		461		542
Accumulated other comprehensive income		18		20
Total stockholders’ equity		2,493		2,576
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	7,154	$	7,406

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

12

AMEREN ILLINOIS COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Six Months Ended June 30,
	2011		2010(a)
Cash Flows From Operating Activities:
Net income	$	72	$	105
Income from discontinued operations, net of tax		-		(21)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		106		106
Amortization of debt issuance costs and premium/discounts		4		5
Deferred income taxes and investment tax credits, net		86		34
Other		(1)		(1)
Changes in assets and liabilities:
Receivables		45		68
Materials and supplies		53		60
Accounts and wages payable		(3)		(32)
Taxes accrued		21		5
Assets, other		32		(28)
Liabilities, other		(24)		(27)
Pension and other postretirement benefits		14		12
Operating cash flows provided by discontinued operations		-		46
Net cash provided by operating activities		405		332
Cash Flows From Investing Activities:
Capital expenditures		(174)		(147)
Returns from (advances to) ATXI for construction		49		(6)
Proceeds from intercompany note receivable – Genco		-		45
Net investing activities used in discontinued operations		-		(3)
Net cash used in investing activities		(125)		(111)
Cash Flows From Financing Activities:
Dividends on common stock		(150)		(67)
Dividends on preferred stock		(2)		(3)
Maturities of long-term debt		(150)		-
Capital contribution from parent		6		-
Generator advances for construction refunded, net of receipts		(53)		(29)
Net financing activities used in discontinued operations		-		(45)
Net cash used in financing activities		(349)		(144)
Net change in cash and cash equivalents		(69)		77
Cash and cash equivalents at beginning of year		322		306
Cash and cash equivalents at end of period	$	253	$	383
Noncash investing activity – asset transfer from ATXI	$	-	$	1

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

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

13

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions)

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Operating Revenues	$	260	$	275	$	501	$	542
Operating Expenses:
Fuel		130		136		241		259
Purchased power		18		18		18		20
Other operations and maintenance		45		45		90		94
Depreciation and amortization		25		25		49		49
Taxes other than income taxes		5		6		12		13
Total operating expenses		223		230		410		435
Operating Income		37		45		91		107
Other Income and Expenses:
Miscellaneous income		-		1		-		1
Miscellaneous expense		-		-		-		1
Total other income		-		1		-		-
Interest Charges		14		20		31		39
Income Before Income Taxes		23		26		60		68
Income Taxes		10		12		25		30
Net Income		13		14		35		38
Less: Net Income Attributable to Noncontrolling Interest		-		1		1		2
Net Income Attributable to Ameren Energy Generating Company	$	13	$	13	$	34	$	36

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)

	June 30,     2011		December 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	7	$	6
Advances to money pool		-		25
Accounts receivable – affiliates		98		126
Miscellaneous accounts and notes receivable		54		19
Materials and supplies		121		130
Mark-to-market derivative assets		20		26
Other current assets		10		4
Total current assets		310		336
Property and Plant, Net		2,237		2,248
Investments and Other Assets:
Intangible assets		-		3
Other assets		22		24
TOTAL ASSETS	$	2,569	$	2,611
LIABILITIES AND EQUITY
Current Liabilities:
Accounts and wages payable	$	64	$	62
Accounts payable – affiliates		25		23
Current portion of tax payable – Ameren Illinois		11		8
Taxes accrued		21		20
Interest accrued		13		13
Mark-to-market derivative liabilities		5		9
Mark-to-market derivative liabilities – affiliates		1		5
Current accumulated deferred income taxes, net		17		13
Other current liabilities		10		12
Total current liabilities		167		165
Credit Facilitity Borrowings		-		100
Long-term Debt, Net		824		824
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		290		253
Accumulated deferred investment tax credits		3		3
Tax payable – Ameren Illinois		64		72
Asset retirement obligations		75		74
Pension and other postretirement benefits		84		88
Other deferred credits and liabilities		17		23
Total deferred credits and other liabilities		533		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		427		393
Accumulated other comprehensive loss		(43)		(44)
Total Ameren Energy Generating Company stockholder’s equity		1,033		998
Noncontrolling Interest		12		11
Total equity		1,045		1,009
TOTAL LIABILITIES AND EQUITY	$	2,569	$	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)

		Six Months Ended June 30,
		2011		2010
Cash Flows From Operating Activities:
Net income		$	35	$	38
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sales of properties			(11)		(5)
Net mark-to-market (gain) loss on derivatives			(6)		4
Depreciation and amortization			51		56
Amortization of debt issuance costs and premium/discounts			1		2
Deferred income taxes and investment tax credits, net			39		31
Other			1		-
Changes in assets and liabilities:
Receivables			(28)		4
Materials and supplies			9		17
Accounts and wages payable			13		(11)
Taxes accrued			1		20
Assets, other			(2)		5
Liabilities, other			(12)		(17)
Pension and other postretirement benefits			(3)		3
Net cash provided by operating activities			88		147
Cash Flows From Investing Activities:
Capital expenditures			(84)		(59)
Proceeds from sales of properties			48		18
Money pool advances, net			25		(21)
Net cash used in investing activities			(11)		(62)
Cash Flows From Financing Activities:
Credit facility repayments, net			(100)		-
Note payable – affiliates			-		(84)
Capital contribution from parent			24		-
Net cash used in financing activities	��		(76)		(84)
Net change in cash and cash equivalents			1		1
Cash and cash equivalents at beginning of year			6		6
Cash and cash equivalents at end of period		$	7	$	7

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

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AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY

AMEREN ILLINOIS COMPANY (Consolidated)

AMEREN ENERGY GENERATING COMPANY (Consolidated)

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

June 30, 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 and in the Form 10-K.

• 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.

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

• Resources Company, or Ameren Energy Resources Company, LLC, consists of non-rate-regulated operations, including Ameren Energy Generating Company (Genco), AmerenEnergy Resources Generating Company (AERG), Ameren Energy Marketing Company (Marketing Company) and AmerenEnergy Medina Valley Cogen, LLC (Medina Valley). Genco operates a merchant electric generation business in Illinois. Genco has an 80% ownership interest in EEI.

Ameren has various other subsidiaries responsible for activities such as the provision of 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 Ameren Illinois Merger. Upon consummation of the Ameren Illinois Merger, the separate legal existence of CILCO and IP terminated. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. The Ameren Illinois 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 Ameren Illinois included purchase accounting adjustments related to Ameren’s acquisition of CILCORP in 2003. Ameren Illinois accounted for the AERG distribution as a spinoff. Ameren Illinois transferred AERG to Ameren based on AERG’s carrying value. Ameren Illinois 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, Ameren Illinois 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.

During the second quarter 2011, Genco identified an error in the cash flow statement classification of a capital contribution from Ameren that impacted Genco’s year ended December 31, 2010, and three months ended March 31, 2011, consolidated statements of cash flows. For the year ended December 31, 2010, Genco’s reported cash flows provided by operating activities were $280 million and cash flows used in financing activities were $251

17

million. As corrected, Genco’s cash flows provided by operating activities were $304 million and cash flows used in financing activities were $275 million. For the three months ended March 31, 2011, Genco’s reported cash flows provided by operating activities were $100 million, and Genco had no reported cash flows from financing activities. As corrected, Genco’s cash flows provided by operating activities were $76 million and cash flows provided by financing activities were $24 million. The error was corrected in Genco’s six months ended June 30, 2011, consolidated statement of cash flows, included herein. This correction had no impact on Ameren’s previously reported consolidated statement of cash flows.

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three months and six months ended June 30, 2011, and 2010. The number of restricted stock shares and performance share units outstanding had an immaterial impact on earnings per share.

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

A summary of nonvested shares as of June 30, 2011, and changes during the six months ended June 30, 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		-			-		518			28.48
Forfeitures		(10,261	)		26.14		(560	)		50.45
Vested(d)		(131,343	)		30.67		(63,574	)		49.47
Nonvested at June 30, 2011		1,733,126		$	26.58		19,538		$	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 $4 million and $2 million for the three months ended June 30, 2011, and 2010, respectively, and a related tax benefit of $2 million and $1 million for the three months ended June 30, 2011, and 2010, respectively. Ameren recorded compensation expense of $7 million for each of the six-month periods ended June 30, 2011, and 2010, respectively, and a related tax benefit of $3 million for each of the six-month periods ended June 30, 2011, and 2010, respectively. As of June 30, 2011, total compensation expense of $27 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 22 months.

Accounting Changes

Disclosures about Fair Value Measurements

See Note 7 - Fair Value Measurements for recently adopted guidance on fair value measurements.

In May 2011, FASB issued authoritative guidance regarding fair value measurements. The guidance amends the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments will not impact the Ameren Companies’ results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. This guidance will become effective for the Ameren Companies for periods starting after December 31, 2011.

18

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance with respect to comprehensive income will not impact the Ameren Companies’ results of operations, financial positions, or liquidity or the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amended guidance will only change the presentation of comprehensive income in the financial statements. The new accounting guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. This guidance will become effective for the Ameren Companies for periods starting after December 31, 2011.

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 June 30, 2011, Ameren’s and Ameren Illinois’ 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.Ameren, Ameren Missouri and Genco classify emission allowances and renewable energy credits as intangible assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

In July 2011, the EPA issued the CSAPR, which will create new allowances for SO₂ and NO_x emissions, thereby restricting the use of existing SO₂and NO_x allowances to the acid rain program and NO_x budget trading program, respectively. In anticipation of the CSAPR announcement, observable market prices for existing emission allowances declined materially. Consequently, during the second quarter of 2011, Ameren and Genco recorded a noncash pretax impairment charge to other operations and maintenance expense of $2 million and $1 million, respectively. Ameren Missouri recorded a $1 million impairment of its SO₂ emission allowances by reducing a previously established regulatory liability relating to the SO₂emission allowances, which had no impact to earnings. See Note 9 - Commitments and Contingencies for additional information on emission allowances and the CSAPR.

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, net of gains from emission allowance sales for Ameren, Ameren Missouri and Genco during the three and six months ended June 30, 2011, and 2010. The table below does not include the intangible asset impairment charges referenced above.

	Three Months						Six Months
	2011			2010			2011			2010
Ameren(a)	$	1		$	7		$	2		$	10
AMO		-			(b	)		-			(b	)
Genco(a)		1			5			2			8
AERG(a)		(b	)		2			(b	)		2

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

(b) Less than $1 million.

At June 30, 2011, Ameren’s and Ameren Missouri’s intangible assets also included renewable energy credits obtained through wind and solar power purchase agreements. The book value of each of Ameren’s and Ameren Missouri’s renewable energy credits as of June 30, 2011, was $3 million.

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and natural gas customer bills and Ameren Illinois 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 Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in 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 and six months ended June 30, 2011 and 2010:

	Three Months				Six Months
	2011		2010		2011		2010
Ameren	$	44	$	44	$	95	$	90
AMO		34		33		63		58
AIC		10		11		32		32

Uncertain Tax Positions

The amount of unrecognized tax benefits as of June 30, 2011, was $198 million, $146 million, $33 million, and $16 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of June 30, 2011, that would impact the effective tax rate, if recognized, was $2 million, $2 million, $(1) million and $1 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

In the second quarter of 2011, final settlement for the 2005 and 2006 years was reached with the Internal Revenue Service, which resulted in the reduction of uncertain tax liabilities by $39 million, $17 million, $12 million and $4 million

19

for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. Ameren’s federal income tax returns for the years 2007 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, Ameren Illinois and Genco increased compared to December 31, 2010, to reflect the accretion of obligations to their fair values.

Noncontrolling Interests

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 interests at Ameren and Genco for the three and six months ended June 30, 2011, and 2010, is shown below:

	Three Months						Six Months
	2011			2010			2011			2010
Ameren:
Noncontrolling interest, beginning of period	$	155		$	206		$	154		$	204
Net income attributable to noncontrolling interest		1			3			4			7
Dividends paid to noncontrolling interest holders		(1	)		(3	)		(3	)		(5	)
Noncontrolling interest, end of period	$	155		$	206		$	155		$	206
Genco:
Noncontrolling interest, beginning of period	$	12		$	10		$	11		$	9
Net income attributable to noncontrolling interest		-			1			1			2
Noncontrolling interest, end of period	$	12		$	11		$	12		$	11

Genco Asset Sale

In June 2011, Genco completed the sale of its remaining interest in the Columbia CT facility to the city of Columbia, Missouri. Genco received cash proceeds of $45 million from the sale. Genco recognized an $8 million pretax gain during the second quarter of 2011 relating to this sale. Effective with the sale, the power purchase agreements between Marketing Company and the city of Columbia were 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

20

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 continued to pay into the Stoddard Circuit Court’s registry its monthly FAC payments that related to electric service received 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 June 30, 2011, the aggregate amount held in the Stoddard Circuit Court’s registry was $16 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 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. A decision by the Missouri Court of Appeals is expected in 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 June 30, 2011, the aggregate amount held by the Cole County Circuit Court, excluding the bond amount, was $8 million.

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.

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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 MoPSC 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 becomes 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.

2011 Electric Rate Order

On July 13, 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of approximately $173 million, including $52 million related to an 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. The revenue increase was based on a 10.2% return on equity, a capital structure composed of 52.2% common equity, and a rate base of approximately $6.6 billion. The rate changes became effective on July 31, 2011. The MoPSC order approved the continued use of Ameren Missouri’s vegetation management and infrastructure cost tracker, pension and postretirement benefit cost tracker, and FAC at the current 95% sharing level. The MoPSC order shortened the FAC recovery and refund period from 12 months to 8 months. The MoPSC order denied Ameren Missouri’s request for the ability to recover any under-recovery of fixed costs as a result of lower sales volumes from the implementation of energy efficiency measures.

Additionally, the MoPSC order provided for a tracking mechanism for uncertain income tax positions. The order provides that reserves for uncertain tax positions do not reduce rate base. However, when an uncertain tax position liability is resolved, the order requires the creation of a regulatory asset or regulatory liability to reflect the time value (using the weighted average cost of capital in the order) of the difference between the uncertain tax position liability that was excluded from rate base and the final tax liability. The resulting regulatory asset or liability will be amortized over three years beginning on the effective date of the next electric rate case.

The 2011 electric rate order also allowed for the full recovery of investments for the Sioux energy center scrubbers and related 2011 property taxes for the Sioux and Taum Sauk energy centers. However, the MoPSC order disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance. As a result of the order, Ameren and Ameren Missouri will each record a pretax charge to earnings of $89 million, relating to the Taum Sauk disallowance, in the third quarter ending September 30, 2011.

Further, the MoPSC order adjusted or established the recovery period of multiple regulatory assets and regulatory liabilities. The following table summarizes the changes to the recovery period of regulatory assets and regulatory liabilities as directed in the MoPSC’s July 2011 rate order. The recovery periods became effective on August 1, 2011.

Regulatory Assets and Liabilities	Regulatory Asset (Liability) Balance at June 30, 2011			Recovery Period Ends
Demand-side costs(a)	$	33			July 2017
Construction accounting for pollution control equipment(a)		25			July 2038
SO2 emissions allowances sales tracker(b)		8			July 2013
FERC-ordered MISO resettlements(b)		2			July 2013
2006 Storm costs(b)		1			July 2013
Vegetation management and infrastructure inspection(b)		(3	)		July 2013
Pension and postretirement benefit cost tracker for 2010 costs(a)		(11	)		July 2016
Total	$	55

(a) Recovery period first established in the MoPSC’s July 2011 rate order.

(b) Previous recovery period was extended.

On July 1, 2011, a new law took effect that reformed the judicial appeal process of MoPSC rate orders. Among other items, the new law allows appeals to be made directly to the appellate court, bypassing the circuit court. The new law provides that rates cannot be stayed; however, the Appellate Court could direct the MoPSC to revise the rates

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based on its appeal ruling. Such rate revisions could be ordered to be applied retroactively. The provisions of this new law will apply to any judicial appeals of the MoPSC’s July 2011 rate order.

In July 2011, Ameren Missouri and other parties to the rate case filed for rehearing of various aspects of the order including the disallowance of Taum Sauk enhancements. The MoPSC rejected the requests. Subsequently, Ameren Missouri appealed the disallowance of Taum Sauk enhancements to the Missouri Court of Appeals, Western District. Ameren Missouri cannot predict the ultimate outcome of its appeal.

FAC Prudence Review

Missouri law requires the MoPSC to complete prudence reviews of Ameren Missouri’s FAC at least every 18 months. In April 2011, the MoPSC issued an order with respect to its prudence 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. As a result of the order, Ameren Missouri recorded a pretax charge to earnings of $18 million, including $1 million for interest, in the second quarter of 2011 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 disagrees with the MoPSC order’s classification of these sales and believes that the terms of its FAC tariff did not provide for the inclusion of these sales in the FAC calculation. In May 2011, Ameren Missouri filed a rehearing request with the MoPSC, which was denied. In June 2011, Ameren Missouri filed an appeal with the Cole County Circuit Court. A decision is expected from the Cole County Circuit Court in 2011. Separately, in July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren Missouri to defer, as a regulatory asset, fixed costs totaling $36 million that were not recovered from Noranda as a result of the loss of load caused by the severe 2009 ice storm for potential recovery in a future electric rate case. We cannot predict the ultimate outcome of these regulatory or judicial proceedings.

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 prudence review of the FAC for this subsequent period. Consequently, the MoPSC order issued in April 2011 did not address any pretax earnings associated with the same long-term partial requirements contracts subsequent to September 30, 2009. The next prudence review is scheduled to be initiated in September 2011. 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

In February 2011, Ameren Illinois filed a request with the ICC to increase its annual revenues for electric delivery service. The currently pending request, as revised in July 2011, seeks to increase annual revenues for electric delivery service by $40 million. The revised electric rate increase request was based on an 11.0% return on equity, a capital structure composed of 52.9% common equity, and a rate base of $2 billion.

In July 2011, Ameren Illinois also revised its February 2011 request with the ICC to increase its annual revenues for natural gas delivery service. The currently pending request seeks to increase annual revenues for natural gas delivery service by $50 million. The revised natural gas rate increase request was based on a 10.75% return on equity, a capital structure composed of 52.9% common equity, and a rate base of $957 million.

In an attempt to limit regulatory lag, Ameren Illinois used a future test year, 2012, in each of these rate requests. In its July 2011 revision, Ameren Illinois withdrew its request for a rider mechanism for its pension costs.

In June 2011, the ICC staff responded to Ameren Illinois’ original filed requests. The ICC staff recommended a net decrease in revenues for electric delivery service of $10 million, based on a 9.72% return on equity, a capital structure composed of 51.8% common equity, and a rate base of $2 billion. The ICC staff recommended a net increase in revenues for natural gas delivery service of $16 million, based on an 8.9% return on equity, a capital structure composed of 51.8% common equity, and a rate base of $942 million. Other parties also made recommendations through testimony filed in the electric and natural gas delivery service rate cases.

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A decision by the ICC in these proceedings is required by January 2012. Ameren Illinois 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 Ameren Illinois to recover its costs and earn a reasonable return on its investments when the rate changes go into effect.

Federal

Electric Transmission Investment

FERC, in its order issued in May 2011, approved transmission rate incentives for ATX, Ameren Missouri and Ameren Illinois for two new transmission projects. These initial projects, subject to MISO approval, consist of a potential $1 billion investment in high voltage transmission projects in Illinois and Missouri. The FERC order approved the following rate mechanisms with respect to ATX’s initial portfolio of transmission projects:

• Full recovery of financing costs associated with construction work in progress before the asset is placed in service;

• Recovery of prudently incurred costs in developing project facilities that might later be abandoned due to issues outside the company’s control;

• Use of a hypothetical capital structure reflecting the capital structure of Ameren Illinois as of December 31, 2009, which would afford ATX a capital structure that resembles that of a utility company; and

• Permission to allow ATX to recover operating and maintenance costs incurred in the early development stages of the projects.

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 energy center site. In 2009, Ameren Missouri suspended its efforts to build a new nuclear unit at its existing Missouri nuclear energy center site, and the NRC suspended review of the COLA.

Ameren Missouri is considering filing an application to obtain an ESP from the NRC for the Callaway energy center 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. Attempts to pass legislation to maintain an option for nuclear power in the state of Missouri by recovering the costs of the ESP, subject to appropriate consumer protections, were not successful during the 2011 spring Missouri legislative session. However, support for nuclear power exists in the state of Missouri, which could lead to the passage of an ESP recovery mechanism in future legislative sessions. Ameren Missouri’s pursuit of an ESP is dependent upon enactment of a legislative framework ensuring cost recovery.

As of June 30, 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 options to maximize the value of its investment in this project. If 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 June 30, 2011, and excludes issued letters of credit:

2010 Missouri Credit Agreement ($800 million)	Ameren (Parent)			Ameren Missouri			Total
Average daily borrowings outstanding during 2011	$	181		$	-		$	181
Outstanding credit facility borrowings at period end		200			-			200
Weighted-average interest rate during 2011		2.31	%		-			2.31	%
Peak credit facility borrowings during 2011(a)	$	340		$	-		$	340
Peak interest rate during 2011		4.30	%		-			4.30	%
2010 Genco Credit Agreement ($500 million)		Ameren (Parent)			Genco			Total
Average daily borrowings outstanding during 2011	$	-		$	83		$	83
Outstanding credit facility borrowings at period end		-			-			-
Weighted-average interest rate during 2011		-			2.30	%		2.30	%
Peak credit facility borrowings during 2011(a)	$	-		$	100		$	100
Peak interest rate during 2011		-			2.31	%		2.31	%

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(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 six months of 2011 were $440 million.

Neither Ameren nor Ameren Illinois borrowed under the 2010 Illinois Credit Agreement during the six months ended June 30, 2011.

The 2010 Credit Agreements are used for cash borrowings, to issue letters of credit, and to support borrowings under Ameren’s and Ameren Missouri’s $500 million commercial paper programs. Any of the 2010 Credit Agreements are available to Ameren to support its commercial paper programs, subject to borrowing sublimits. At June 30, 2011, Ameren had $317 million of commercial paper outstanding and $15 million of letters of credit outstanding. Based on outstanding borrowings and letters of credit issued under the 2010 Credit Agreements as of June 30, 2011, as well as commercial paper outstanding as of such date, the aggregate amount of credit capacity available under the 2010 Credit Agreements at June 30, 2011, was $1.6 billion.

In June 2011, Ameren Missouri received approval from the MoPSC to extend the expiration of its borrowing sublimit under the 2010 Missouri Credit Agreement to September 10, 2013.

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 June 30, 2011, Ameren had $317 million of commercial paper outstanding, which reduced the available amounts under these agreements. During the first six months of 2011, Ameren had average daily commercial paper balances outstanding of $338 million with a weighted-average interest rate of 0.87%. The peak short-term commercial paper outstanding and peak interest rate during the first six months of 2011 were $400 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 contained in the 2010 Credit Agreements and the $20 Million Facility. See Note 4 - Credit Facility Borrowings and Liquidity under Part II, Item 8, of 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 with respect 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, Ameren Illinois 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 June 30, 2011, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 49%, 47%, 40% and 45%, for Ameren, Ameren Missouri, Ameren Illinois 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 June 30, 2011, was 5.0 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 June 30, 2011, Ameren’s consolidated indebtedness ratio, calculated in accordance with the provisions of the $20 Million Facility, was 49%. 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.

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None of the Ameren Companies’ credit agreements or other financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At June 30, 2011, management believes that the Ameren Companies were in compliance with their credit agreements’ 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, Ameren Illinois 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 and the commercial paper programs. 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 and six months ended June 30, 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 borrowing authorizations, to access funding from the 2010 Credit Agreements and the commercial paper programs 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 June 30, 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 and six months ended June 30, 2011, was 0.72% and 0.93%, respectively (2010 - 1.0% and 0.81%, respectively).

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 and six months ended June 30, 2011.

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

Under DRPlus, pursuant to effective SEC Form S-3 registration statements, 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 $15 million and 1.2 million new shares valued at $32 million in the three and six months ended June 30, 2011, respectively.

Ameren Illinois

In June 2011, Ameren Illinois’ 6.625% $150 million senior secured notes matured and were repaid and retired using available cash on hand.

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Indenture Provisions and Other Covenants

Ameren Missouri’s and Ameren Illinois’ indenture provisions and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois 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 June 30, 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
Ameren Missouri	³2.0		3.4	$	2,070		³2.5		99.0	$	1,650
Ameren Illinois	³2.0		7.0		3,230	(d)	³1.5		3.1		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 $765 million at Ameren Missouri and Ameren Illinois, respectively.

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

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

Ameren’s indenture 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, Ameren Illinois 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, Ameren Illinois 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 Ameren Illinois 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 June 30, 2011.

Ameren Illinois’ 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. Ameren Illinois committed to FERC to maintain a minimum 30% ratio of common stock equity to total capitalization following the Ameren Illinois Merger and AERG distribution. As of June 30, 2011, Ameren Illinois’ ratio of common stock equity to total capitalization was 56%.

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 June 30, 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)	4.6	£60%(b)	43%

(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 for the most recently ended four fiscal quarters and 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 the related interest expense. Money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests.

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Genco’s debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody’s and S&P, after giving effect to additional indebtedness, each provide a rating affirmation of the rating then existing with respect with securities issued under the indenture.

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 June 30, 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.

NOTE 5 - OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the three and six months ended June 30, 2011, and 2010:

	Three Months				Six Months
	2011		2010		2011		2010
Ameren:(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	9	$	13	$	15	$	26
Interest income on industrial development revenue bonds		7		7		14		14
Interest and dividend income		1		1		2		2
Other		-		3		2		4
Total miscellaneous income	$	17	$	24	$	33	$	46
Miscellaneous expense:
Donations	$	1	$	1	$	3	$	3
Other		4		1		7		6
Total miscellaneous expense	$	5	$	2	$	10	$	9
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	9	$	12	$	14	$	25
Interest income on industrial development revenue bonds		7		7		14		14
Interest and dividend income		-		1		1		1
Other		-		-		-		1
Total miscellaneous income	$	16	$	20	$	29	$	41
Miscellaneous expense:
Donations	$	1	$	-	$	2	$	1
Other		2		1		4		2
Total miscellaneous expense	$	3	$	1	$	6	$	3
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	-	$	1	$	1	$	1
Interest and dividend income		-		-		-		1
Other		1		1		2		2
Total miscellaneous income	$	1	$	2	$	3	$	4
Miscellaneous expense:
Donations	$	-	$	1	$	-	$	1
Other		1		-		2		3
Total miscellaneous expense	$	1	$	1	$	2	$	4
Genco:
Miscellaneous income:
Other	$	-	$	1	$	-	$	1
Total miscellaneous income	$	-	$	1	$	-	$	1
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, power, and uranium. Such price fluctuations may cause the following:

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• 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 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.

The following table presents open gross derivative volumes by commodity type as of June 30, 2011, and December 31, 2010:

	Quantity (in millions, except as indicated)
Commodity	NPNS Contracts(a)						Cash Flow Hedges(b)						Other Derivatives(c)						Derivatives That Qualify for Regulatory Deferral(d)
	2011			2010			2011			2010			2011			2010			2011			2010
Coal (in tons)
AMO		36			46			(e	)		(e	)		(e	)		(e	)		(e	)		(e	)
Genco		24			21			(e	)		(e	)		(e	)		(e	)		(e	)		(e	)
Other(f)		6			6			(e	)		(e	)		(e	)		(e	)		(e	)		(e	)
Ameren		66			73			(e	)		(e	)		(e	)		(e	)		(e	)		(e	)
Heating oil (in gallons)
AMO		(e	)		(e	)		(e	)		(e	)		(e	)		(e	)		62			80
Genco		(e	)		(e	)		(e	)		(e	)		31			43			(e	)		(e	)
Other(f)		(e	)		(e	)		(e	)		(e	)		9			12			(e	)		(e	)
Ameren		(e	)		(e	)		(e	)		(e	)		40			55			62			80
Natural gas (in mmbtu)
AMO		10			13			(e	)		(e	)		3			2			21			21
AIC		62			85			(e	)		(e	)		(e	)		(e	)		175			173
Genco		(e	)		(e	)		(e	)		(e	)		3			3			(e	)		(e	)
Other(f)		(e	)		(e	)		(e	)		(e	)		20			16			(e	)		(e	)
Ameren		72			98			(e	)		(e	)		26			21			196			194
Power (in megawatthours)
AMO		2			2			(e	)		(e	)		1			1			3			5
AIC		12			(e	)		(e	)		(e	)		(e	)		(e	)		31			26
Genco		(e	)		(e	)		(e	)		(e	)		2			3			(e	)		(e	)
Other(f)		65			61			21			2			51			57			(14	)		(13	)
Ameren		79			63			21			2			54			61			20			18
Uranium (pounds in thousands)
AMO		5,710			5,810			(e	)		(e	)		(e	)		(e	)		458			185
Ameren		5,710			5,810			(e	)		(e	)		(e	)		(e	)		458			185

(a) Contracts through December 2014, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of June 30, 2011.

(b) Contracts through December 2013 for power as of June 30, 2011.

(c) Contracts through December 2013, December 2012, and May 2015 for heating oil, natural gas, and power, respectively, as of June 30, 2011.

(d) Contracts through December 2013, October 2016, May 2032 and December 2013 for heating oil, natural gas, power, and uranium, respectively, as of June 30, 2011.

(e) Not applicable.

(f) Includes AERG contracts for coal and heating oil, Marketing Company contracts for natural gas and power, and intercompany eliminations for power.

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.

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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 Ameren Illinois 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.

The following table presents the carrying value and balance sheet location of all derivative instruments as of June 30, 2011, and December 31, 2010:

	Balance Sheet Location	Ameren(a)		Ameren Missouri			Ameren Illinois			Genco
2011:
Derivative assets designated as hedging instruments
Commodity contracts:
Power	MTM derivative assets	$	5	$	-		$	(b	)	$	-
	Other assets		2		-			-			-
	Total assets	$	7	$	-		$	-		$	-
Derivative liabilities designated as hedging instruments
Commodity contracts:
Power	MTM derivative liabilities	$	3	$	(b	)	$	-		$	-
	Other deferred credits and liabilities		4		-			-			-
	Total liabilities	$	7	$	-		$	-		$	-
Derivative assets not designated as hedging instruments(c)
Commodity contracts:
Heating oil	MTM derivative assets	$	49	$	29		$	(b	)	$	15
	Other assets		23		14			-			7
Natural gas	MTM derivative assets		5		-			(b	)		1
	Other current assets		-		-			2			-
	Other assets		1		-			-			-
Power	MTM derivative assets		100		29			(b	)		4
	Other current assets		-		-			1			-
	Other assets		85		1			68			-
	Total assets	$	263	$	73		$	71		$	27
Derivative liabilities not designated as hedging instruments(c)
Commodity contracts:
Heating oil	MTM derivative liabilities	$	4	$	(b	)	$	-		$	1
	Other current liabilities		-		2			-			-
Natural gas	MTM derivative liabilities		75		(b	)		60			2
	Other current liabilities		-		10			-			-
	Other deferred credits and liabilities		63		10			53			-
Power	MTM derivative liabilities		52		(b	)		4			2
	MTM derivative liabilities - affiliates		-		(b	)		173			1
	Other current liabilities		-		3			-			-
	Other deferred credits and liabilities		14		1			96			-
Uranium	MTM derivative liabilities		1		(b	)		-			-
	Other current liabilities		-		1			-			-
	Other deferred credits and liabilities		1		1			-			-
	Total liabilities	$	210	$	28		$	386		$	6
2010:
Derivative assets designated as hedging instruments
Commodity contracts:
Power	MTM derivative assets	$	3	$	-		$	(b	)	$	-
	Other assets		2		-			-			-
	Total assets	$	5	$	-		$	-		$	-
Derivative liabilities designated as hedging instruments
Commodity contracts:
Power	MTM derivative liabilities	$	1	$	(b	)	$	-		$	-
	Total liabilities	$	1	$	-		$	-		$	-

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	Balance Sheet Location	Ameren(a)			Ameren Missouri			Ameren Illinois			Genco
Derivative assets not designated as hedging instruments(c)
Commodity contracts:
Heating oil	MTM derivative assets	$	42		$	24		$	(b	)	$	14
	Other current assets		-			-			-			-
	Other assets		22			13			-			7
Natural gas	MTM derivative assets		4			1			(b	)		1
	Other current assets		-			-			1			-
	Other assets		1			-			1			-
Power	MTM derivative assets		78			8			(b	)		11
	Other current assets		-			-			2			-
	Other assets		20			-			6			-
Uranium	MTM derivative assets		2			2			(b	)		-
	Other current assets		-			-			-			-
	Total assets	$	169		$	48		$	10		$	33
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 June 30, 2011, and December 31, 2010:

	Ameren			Ameren Missouri			Ameren Illinois			Genco			Other(a)
2011:
Cumulative gains (losses) deferred in accumulated OCI:
Power derivative contracts(b)	$	3		$	-		$	-		$	-		$	3
Interest rate derivative contracts(c)(d)		(9	)		-			-			(9	)		-
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Heating oil derivative contracts(e)		35			35			-			-			-
Natural gas derivative contracts(f)		(131	)		(20	)		(111	)		-			-
Power derivative contracts(g)		91			26			(204	)		-			269
Uranium derivative contracts(h)		(2	)		(2	)		-			-			-
2010:
Cumulative gains (losses) deferred in accumulated OCI:
Power derivative contracts(b)	$	8		$	-		$	-		$	-		$	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	)		-			350
Uranium derivative contracts(h)		2			2			-			-			-

(a) Includes amounts for Marketing Company 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 December 2013 as of June 30, 2011. Current gains of $3 million and $8 million were recorded at Ameren as of June 30, 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 June 30, 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 June 30, 2011, and December 31, 2010, was a loss of $9 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 June 30, 2011. Current gains deferred as regulatory liabilities include $24 million and $24 million at Ameren and Ameren

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Missouri as of June 30, 2011, respectively. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri as of June 30, 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 Ameren Illinois, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $69 million, $9 million, and $60 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 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 Ameren Illinois, 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 2032 at Ameren and Ameren Illinois and through December 2012 at Ameren Missouri, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $29 million, $28 million, and $1 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $5 million, $2 million, and $177 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $8 million, $6 million, and $2 million at Ameren, Ameren Missouri and Ameren Illinois, 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 Ameren Illinois, respectively, as of December 31, 2010.

(h) Represents net losses and gains on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through December 2013 as of June 30, 2011. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of June 30, 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 June 30, 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:
AMO	$	-	$	22	$	2	$	5	$	39	$	7	$	-	$	-	$	75
AIC		-		-		29		-		2		-		-		-		31
Genco		-		12		1		1		3		-		4		-		21
Other(b)		333		7		7		10		47		217		1		68		690
Ameren		333		41		39		16		91		224		5		68		817
2010:
AMO	$	-	$	21	$	1	$	2	$	5	$	11	$	1	$	-	$	41
AIC		-		-		3		-		1		-		-		-		4
Genco		-		6		2		1		1		-		6		-		16
Other(b)		410		3		10		19		65		539		3		72		1,121
Ameren		410		30		16		22		72		550		10		72		1,182

(a) Primarily comprised of Marketing Company’s exposure to Ameren Illinois 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 under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.

(b) Includes amounts for Marketing Company, AERG, and AFS.

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The following table presents the amount of cash collateral held from counterparties, as of June 30, 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)	$	-	$	-	$	-	$	-	$	-	$	-	$	-	$	-	$	-
2010:
Ameren(a)	$	-	$	-	$	-	$	-	$	-	$	-	$	-	$	1	$	1

(a) Represents amounts held by Marketing Company. As of June 30, 2011, and December 31, 2010, Ameren registrant subsidiaries held no cash collateral.

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 June 30, 2011, other collateral consisted of letters of credit in the amount of $16 million, $1 million, $2 million and $13 million held by Ameren, Ameren Missouri, Ameren Illinois and Marketing Company, 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 Ameren Illinois, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of June 30, 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:
AMO	$	-	$	10	$	1	$	3	$	33	$	7	$	-	$	-	$	54
AIC		-		-		27		-		-		-		-		-		27
Genco		-		4		1		-		1		-		3		-		9
Other(b)		317		4		6		5		35		205		-		67		639
Ameren		317		18		35		8		69		212		3		67		729
2010:
AMO	$	-	$	8	$	-	$	1	$	2	$	10	$	-	$	-	$	21
AIC		-		-		2		-		-		-		-		-		2
Genco		-		1		1		1		1		-		5		-		9
Other(b)		404		1		8		7		56		513		2		71		1,062
Ameren		404		10		11		9		59		523		7		71		1,094

(a) Primarily comprised of Marketing Company’s exposure to Ameren Illinois 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 under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.

(b) Includes amounts for Marketing Company, AERG, and AFS.

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 June 30, 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 June 30, 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 Missouri	$	113	$	5		$                         67
Ameren Illinois		207		91		103
Genco		49		5		26
Other(c)		121		13		59
Ameren		490		114		255
2010:
Ameren Missouri	$	105	$	7		$                        93
Ameren Illinois		233		109		111
Genco		31		-		28
Other(c)		62		18		42
Ameren		431		134		274

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

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(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 Marketing Company and Ameren (parent).

Cash Flow Hedges

The following table presents the pretax net gain or loss for the three and six months ended June 30, 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)
Three Months
2011:
Ameren:(d)
Power	$	(3	)	Operating Revenues - Electric	$	1		Operating Revenues - Electric	$	3
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
Genco:
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
2010:
Ameren:(d)
Power	$	(16	)	Operating Revenues - Electric	$	(10	)	Operating Revenues - Electric	$	(13	)
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
Genco:
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
Six Months
2011:
Ameren:(d)
Power	$	(7	)	Operating Revenues - Electric	$	2		Operating Revenues - Electric	$	2
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
Genco:
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
2010:
Ameren:(d)
Power	$	10		Operating Revenues - Electric	$	(14	)	Operating Revenues - Electric	$	(13	)
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.

34

Other Derivatives

The following table represents the net change in market value for derivatives not designated as hedging instruments for the three and six months ended June 30, 2011, and 2010:

		Location of Gain (Loss) Recognized in Income	Gain (Loss) Recognized in Income
			Three Months						Six Months
			2011			2010			2011			2010
Ameren(a)	Heating oil	Operating Expenses - Fuel	$	(9	)	$	(7	)	$	10		$	(6	)
	Natural gas (generation)	Operating Expenses - Fuel		-			-			-			(1	)
	Power	Operating Revenues - Electric		(5	)		(11	)		(7	)		20
		Total	$	(14	)	$	(18	)	$	3		$	13
Ameren Missouri	Natural gas (generation)	Operating Expenses - Fuel	$	-		$	-		$	(1	)	$	1
	Power	Operating Revenues - Electric		-			-			-			(1	)
		Total	$	-		$	-		$	(1	)	$	-
Genco	Heating oil	Operating Expenses - Fuel	$	(8	)	$	(5	)	$	7		$	(4	)
	Natural gas (generation)	Operating Expenses - Fuel		-			-			-			(1	)
	Power	Operating Revenues		(1	)		-			(1	)		1
		Total	$	(9	)	$	(5	)	$	6		$	(4	)

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

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 and six months ended June 30, 2011, and 2010:

		Gain (Loss) Recognized in Regulatory  Liabilities or Regulatory Assets
		Three Months						Six Months
		2011			2010			2011			2010
Ameren(a)	Heating oil	$	(13	)	$	(9	)	$	16		$	(8	)
	Natural gas		3			25			34			(81	)
	Power		88			33			90			23
	Uranium		(3	)		(1	)		(4	)		(2	)
	Total	$	75		$	48		$	136		$	(68	)
Ameren Missouri	Heating oil	$	(13	)	$	(9	)	$	16		$	(8	)
	Natural gas		1			4			4			(11	)
	Power		23			(9	)		23			7
	Uranium		(3	)		(1	)		(4	)		(2	)
	Total	$	8		$	(15	)	$	39		$	(14	)
Ameren Illinois	Natural gas	$	2		$	21		$	30		$	(70	)
	Power		121			150			148			17
	Total	$	123		$	171		$	178		$	(53	)

(a) Includes amounts for intercompany eliminations.

As part of the 2007 Illinois Electric Settlement Agreement and subsequent Illinois power procurement processes, Ameren Illinois 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 Ameren Illinois. Consequently, Ameren Illinois 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 Ameren Illinois 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 Ameren Illinois’ balance sheet at June 30, 2011, and December 31, 2010:

		2011		2010
AIC	MTM derivative liabilities - affiliates	$	173	$	172
	Other deferred credits and liabilities		95		178
	Total	$	268	$	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

35

default swaps, bond yields, and credit ratings. Ameren recorded losses totaling less than $1 million in the first six months of 2011 and gains totaling less than $1 million in the first six months of 2010 related to valuation adjustments for counterparty default risk. At June 30, 2011, the counterparty default risk valuation adjustment related to net derivative assets totaled $1 million and less than $1 million for Ameren and Genco, respectively. The counterparty default risk valuation adjustment related to net derivative liabilities totaled less than $1 million and $11 million for Ameren Missouri and Ameren Illinois, 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, Ameren Illinois and Genco, respectively.

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 June 30, 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	$	-	$	-	$	72	$	72
	Natural gas		3		-		3		6
	Power		-		18		174		192
	Nuclear Decommissioning Trust Fund(c):
	Cash and cash equivalents		1		-		-		1
	Equity securities:
	U.S. large capitalization		234		-		-		234
	Debt securities:
	Corporate bonds		-		45		-		45
	Municipal bonds		-		2		-		2
	U.S. treasury and agency securities		-		59		-		59
	Asset-backed securities		-		13		-		13
	Other		-		1		-		1
AMO	Derivative assets - commodity contracts(b):
	Heating oil		-		-		43		43
	Power		-		2		28		30
	Nuclear Decommissioning Trust Fund(c):
	Cash and cash equivalents		1		-		-		1
	Equity securities:
	U.S. large capitalization		234		-		-		234
	Debt securities:
	Corporate bonds		-		45		-		45
	Municipal bonds		-		2		-		2
	U.S. treasury and agency securities		-		59		-		59
	Asset-backed securities		-		13		-		13
	Other		-		1		-		1
AIC	Derivative assets - commodity contracts(b):
	Natural gas		-		-		2		2
	Power		-		-		69		69
Genco	Derivative assets - commodity contracts(b):
	Heating oil		-		-		22		22
	Natural gas		1		-		-		1
	Power		-		-		4		4
Liabilities:
Ameren(a)	Derivative liabilities - commodity contracts(b):
	Heating oil	$	-	$	-	$	4	$	4
	Natural gas		18		-		120		138
	Power		-		16		57		73
	Uranium		-		-		2		2
AMO	Derivative liabilities - commodity contracts(b):
	Heating oil		-		-		2		2
	Natural gas		9		-		11		20
	Power		-		1		3		4
	Uranium		-		-		2		2
AIC	Derivative liabilities - commodity contracts(b):
	Natural gas		5		-		108		113
	Power		-		-		273		273
Genco	Derivative liabilities - commodity contracts(b):
	Heating oil		-		-		1		1
	Natural gas		2		-		-		2
	Power		-		-		3		3

36

(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.

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.

37

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 June 30, 2011:

	Net derivative commodity contracts
Three Months	Ameren			Ameren Missouri			Ameren Illinois			Genco			Other(c)
Heating oil:
Beginning balance at April 1, 2011	$	96		$	57		$	(a	)	$	29		$	10
Realized and unrealized gains (losses):
Included in earnings(b)		(5	)		-			(a	)		(3	)		(2	)
Included in regulatory assets/liabilities		(9	)		(9	)		(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(14	)		(9	)		(a	)		(3	)		(2	)
Purchases		1			1			(a	)		-			-
Settlements		(15	)		(8	)		(a	)		(5	)		(2	)
Ending balance at June 30, 2011	$	68		$	41		$	(a	)	$	21		$	6
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011	$	(14	)	$	(8	)	$	(a	)	$	(4	)	$	(2	)
Natural gas:
Beginning balance at April 1, 2011	$	(120	)	$	(12	)	$	(108	)	$	-		$	-
Realized and unrealized gains (losses):
Included in earnings(b)		-			-			-			-			-
Included in regulatory assets/liabilities		(20	)		(1	)		(19	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(20	)		(1	)		(19	)		-			-
Purchases		1			-			1			-			-
Settlements		22			2			20			-			-
Ending balance at June 30, 2011	$	(117	)	$	(11	)	$	(106	)	$	-		$	-
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011	$	(18	)	$	(1	)	$	(17	)	$	-		$	-
Power:
Beginning balance at April 1, 2011	$	31		$	2		$	(325	)	$	3		$	351
Realized and unrealized gains (losses):
Included in earnings(b)		(15	)		-			-			(1	)		(14	)
Included in OCI		5			-			-			-			5
Included in regulatory assets/liabilities		66			(1	)		77			(a	)		(10	)
Total realized and unrealized gains (losses)		56			(1	)		77			(1	)		(19	)
Purchases		50			29			-			-			21
Sales		(7	)		-			-			-			(7	)
Settlements		(16	)		(6	)		44			(1	)		(53	)
Transfers into Level 3		1			-			-			-			1
Transfers out of Level 3		2			1			-			-			1
Ending balance at June 30, 2011	$	117		$	25		$	(204	)	$	1		$	295
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011	$	59		$	(1	)	$	68		$	(1	)	$	(7	)
Uranium:
Beginning balance at April 1, 2011	$	1		$	1		$	(a	)	$	(a	)	$	(a	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(3	)		(3	)		(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(3	)		(3	)		(a	)		(a	)		(a	)
Ending balance at June 30, 2011	$	(2	)	$	(2	)	$	(a	)	$	(a	)	$	(a	)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011	$	(2	)	$	(2	)	$	(a	)	$	(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.

(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

38

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 June 30, 2010:

	Net derivative commodity contracts
Three Months	Ameren			Ameren Missouri			Ameren Illinois			Genco			Other(c)
Heating oil:
Beginning balance at April 1, 2010	$	54		$	31		$	(a	)	$	18		$	5
Realized and unrealized gains (losses):
Included in earnings(b)		(8	)		-			(a	)		(6	)		(2	)
Included in regulatory assets/liabilities		(9	)		(9	)		(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(17	)		(9	)		(a	)		(6	)		(2	)
Purchases		33			17			(a	)		11			5
Settlements		(41	)		(23	)		(a	)		(13	)		(5	)
Ending balance at June 30, 2010	$	29		$	16		$	(a	)	$	10		$	3
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010	$	(16	)	$	(9	)	$	(a	)	$	(5	)	$	(2	)
Natural gas:
Beginning balance at April 1, 2010	$	(162	)	$	(18	)	$	(144	)	$	-		$	-
Realized and unrealized gains (losses):
Included in earnings(b)		-			-			-			-			-
Included in regulatory assets/liabilities		(6	)		(1	)		(5	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(6	)		(1	)		(5	)		-			-
Purchases		-			-			-			-			-
Settlements		30			4			26			-			-
Ending balance at June 30, 2010	$	(138	)	$	(15	)	$	(123	)	$	-		$	-
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010	$	(6	)	$	(1	)	$	(5	)	$	-		$	-
Power:
Beginning balance at April 1, 2010	$	37		$	5		$	(554	)	$	3		$	583
Realized and unrealized gains (losses):
Included in earnings(b)		6			-			-			-			6
Included in OCI		(18	)		-			-			-			(18	)
Included in regulatory assets/liabilities		29			1			98			(a	)		(70	)
Total realized and unrealized gains (losses)		17			1			98			-			(82	)
Purchases		25			5			17			(2	)		5
Sales		2			-			-			3			(1	)
Settlements		(19	)		(6	)		33			(1	)		(45	)
Transfers into Level 3		(1	)		-			-			-			(1	)
Transfers out of Level 3		(7	)		-			-			-			(7	)
Ending balance at June 30, 2010	$	54		$	5		$	(406	)	$	3		$	452
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010	$	(5	)	$	(3	)	$	67		$	-		$	(69	)
Uranium:
Beginning balance at April 1, 2010	$	(3	)	$	(3	)	$	(a	)	$	(a	)	$	(a	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(1	)		(1	)		(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(1	)		(1	)		(a	)		(a	)		(a	)
Ending balance at June 30, 2010	$	(4	)	$	(4	)	$	(a	)	$	(a	)	$	(a	)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010	$	-		$	-		$	(a	)	$	(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.

(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

39

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 six months ended June 30, 2011:

	Net derivative commodity contracts
Six Months	Ameren			Ameren Missouri			Ameren Illinois			Genco			Other(c)
Heating oil:
Beginning balance at January 1, 2011	$	51		$	30		$	(a	)	$	17		$	4
Realized and unrealized gains (losses):
Included in earnings(b)		17			-			(a	)		12			5
Included in regulatory assets/liabilities		22			22			(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		39			22			(a	)		12			5
Purchases		2			2			(a	)		-			-
Settlements		(24	)		(13	)		(a	)		(8	)		(3	)
Ending balance at June 30, 2011	$	68		$	41		$	(a	)	$	21		$	6
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011	$	30		$	18		$	(a	)	$	9		$	3
Natural gas:
Beginning balance at January 1, 2011	$	(148	)	$	(14	)	$	(134	)	$	-		$	-
Realized and unrealized gains (losses):
Included in earnings(b)		-			-			-			-			-
Included in regulatory assets/liabilities		(13	)		(1	)		(12	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(13	)		(1	)		(12	)		-			-
Purchases		1			-			1			-			-
Settlements		43			4			39			-			-
Ending balance at June 30, 2011	$	(117	)	$	(11	)	$	(106	)	$	-		$	-
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011	$	9		$	1		$	8		$	-		$	-
Power:
Beginning balance at January 1, 2011	$	36		$	2		$	(352	)	$	3		$	383
Realized and unrealized gains (losses):
Included in earnings(b)		(18	)		-			-			(1	)		(17	)
Included in OCI		5			-			-			-			5
Included in regulatory assets/liabilities		64			6			47			(a	)		11
Total realized and unrealized gains (losses)		51			6			47			(1	)		(1	)
Purchases		59			29			-			-			30
Sales		(16	)		-			-			-			(16	)
Settlements		(16	)		(12	)		101			(1	)		(104	)
Transfers into Level 3		1			(1	)		-			-			2
Transfers out of Level 3		2			1			-			-			1
Ending balance at June 30, 2011	$	117		$	25		$	(204	)	$	1		$	295
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011	$	59		$	-		$	64		$	(1	)	$	(4	)
Uranium:
Beginning balance at January 1, 2011	$	2		$	2		$	(a	)	$	(a	)	$	(a	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(4	)		(4	)		(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(4	)		(4	)		(a	)		(a	)		(a	)
Ending balance at June 30, 2011	$	(2	)	$	(2	)	$	(a	)	$	(a	)	$	(a	)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011	$	(2	)	$	(2	)	$	(a	)	$	(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.

(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

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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 six months ended June 30, 2010:

	Net derivative commodity contracts
Six Months	Ameren			Ameren Missouri			Ameren Illinois			Genco			Other(c)
Heating oil:
Beginning balance at January 1, 2010	$	60		$	32		$	(a	)	$	21		$	7
Realized and unrealized gains (losses):
Included in earnings(b)		(10	)		-			(a	)		(8	)		(2	)
Included in regulatory assets/liabilities		(11	)		(11	)		(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(21	)		(11	)		(a	)		(8	)		(2	)
Purchases		32			18			(a	)		11			3
Settlements		(42	)		(23	)		(a	)		(14	)		(5	)
Ending balance at June 30, 2010	$	29		$	16		$	(a	)	$	10		$	3
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010	$	(18	)	$	(10	)	$	(a	)	$	(6	)	$	(2	)
Natural gas:
Beginning balance at January 1, 2010	$	(67	)	$	(6	)	$	(61	)	$	-		$	-
Realized and unrealized gains (losses):
Included in earnings(b)		-			-			-			-			-
Included in regulatory assets/liabilities		(109	)		(14	)		(95	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(109	)		(14	)		(95	)		-			-
Purchases		(4	)		-			(4	)		-			-
Settlements		42			5			37			-			-
Ending balance at June 30, 2010	$	(138	)	$	(15	)	$	(123	)	$	-		$	-
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010	$	(81	)	$	(10	)	$	(71	)	$	-		$	-
Power:
Beginning balance at January 1, 2010	$	38		$	(1	)	$	(422	)	$	1		$	460
Realized and unrealized gains (losses):
Included in earnings(b)		24			-			-			2			22
Included in OCI		6			-			-			-			6
Included in regulatory assets/liabilities		7			13			(69	)		(a	)		63
Total realized and unrealized gains (losses)		37			13			(69	)		2			91
Purchases		38			4			17			(4	)		21
Sales		(5	)		1			-			5			(11	)
Settlements		(29	)		(9	)		68			(1	)		(87	)
Transfers into Level 3		(1	)		-			-			-			(1	)
Transfers out of Level 3		(24	)		(3	)		-			-			(21	)
Ending balance at June 30, 2010	$	54	��	$	5		$	(406	)	$	3		$	452
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010	$	(7	)	$	1		$	(79	)	$	1		$	70
Uranium:
Beginning balance at January 1, 2010	$	(2	)	$	(2	)	$	(a	)	$	(a	)	$	(a	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(2	)		(2	)		(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(2	)		(2	)		(a	)		(a	)		(a	)
Ending balance at June 30, 2010	$	(4	)	$	(4	)	$	(a	)	$	(a	)	$	(a	)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010	$	(1	)	$	(1	)	$	(a	)	$	(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.

(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

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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 June 30, 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 three and six months ended June 30, 2011, and 2010, there were no transfers into or out of Level 1.

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 June 30, 2011, and December 31, 2010:

	June 30, 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)	$	6,859	$	7,666	$	7,008	$	7,661
Preferred stock		142		102		142		102
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	3,954	$	4,378	$	3,954	$	4,281
Preferred stock		80		61		80		62
Ameren Illinois:
Long-term debt (including current portion)	$	1,658	$	1,956	$	1,807	$	2,067
Preferred stock		62		41		62		40
Genco:
Long-term debt (including current portion)	$	824	$	843	$	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.

Electric Power Supply Agreements

Ameren Illinois, as an electric load serving entity, must acquire energy sufficient to meet its obligations to customers. In 2011, Ameren Illinois used a RFP process administered by the IPA to procure energy products from June 1, 2011, through May 31, 2014. Marketing Company and Ameren Missouri were winning suppliers in Ameren Illinois’ energy product RFP process. In May 2011, Marketing Company and Ameren Illinois entered into energy product agreements where Marketing Company will sell and Ameren Illinois will purchase approximately 1,747,200 megawatthours at approximately $37 per megawatthour during the twelve months ending May 31, 2012, approximately 1,840,800 megawatthours at approximately $42 per megawatthour during the twelve months ending May 31, 2013, and approximately 650,000 megawatthours at approximately $42 per megawatthour during the twelve months ending May 31, 2014. In May 2011, Ameren Missouri and Ameren Illinois entered into energy product agreements where Ameren Missouri will sell and Ameren Illinois will purchase approximately 16,800 megawatthours at approximately $37 per megawatthour during the twelve months ending May 31, 2012, approximately 40,800 megawatthours at approximately $29 per megawatthour during the twelve months ending May 31, 2013, and approximately 40,800 megawatthours at approximately $28 per megawatthour during the twelve months ending May 31, 2014. The 2012 and 2013 energy product agreements between Ameren Missouri and Ameren Illinois are for off-peak hours only.

Joint Ownership Agreement and Asset Transfer

ATXI and Ameren Illinois have a joint ownership agreement to construct, own, operate, and maintain certain electric transmission assets in Illinois. Under the terms of this

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agreement, Ameren Illinois 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, Ameren Illinois has a variable interest in ATXI, but Ameren Illinois is not the primary beneficiary. Ameren is the primary beneficiary of ATXI, and therefore consolidates ATXI. Currently, there are no construction projects or joint ownership of existing assets under this agreement.

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

In March 2011, Ameren Illinois 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 Ameren Illinois for $20 million. In April 2011, Ameren Illinois paid ATXI for these assets.

Collateral Postings

Under the terms of the 2011, 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 Ameren Illinois 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 energy products, and Marketing Company, as a winning supplier of capacity, financial energy swaps and energy products, may be required to post collateral. As of December 31, 2010, and June 30, 2011, there were no collateral postings required of Ameren Missouri or Marketing Company related to the 2011, 2010 and 2009 Illinois power procurement agreements.

Money Pools

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

The following table presents the impact on Ameren Missouri, Ameren Illinois and Genco of related party transactions for the three and six months ended June 30, 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.

	Income Statement Line Item		Three Months									Six Months
Agreement			AMO			AIC			Genco			AMO			AIC			Genco
Genco and EEI power supply agreements with Marketing Company	Operating Revenues	2011	$	(a	)	$	(a	)	$	246		$	(a	)	$	(a	)	$	485
		2010		(a	)		(a	)		254			(a	)		(a	)		518
Genco gas sales to Medina Valley	Operating Revenues	2011		(a	)		(a	)		(b	)		(a	)		(a	)		2
		2010		(a	)		(a	)		-			(a	)		(a	)		1
Total Operating Revenues		2011	$	(a	)	$	(a	)	$	246		$	(a	)	$	(a	)	$	487
		2010		(a	)		(a	)		254			(a	)		(a	)		519
AIC power supply agreements with Marketing Company	Purchased Power	2011	$	(a	)	$	48		$	(a	)	$	(a	)	$	94		$	(a	)
		2010		(a	)		59			(a	)		(a	)		132			(a	)
EEI power supply agreement with Marketing Company	Purchased Power	2011		(a	)		(a	)		12			(a	)		(a	)		12
		2010		(a	)		(a	)		4			(a	)		(a	)		4
Total Purchased Power		2011	$	(a	)	$	48		$	12		$	(a	)	$	94		$	12
		2010		(a	)		59			4			(a	)		132			4
Ameren Services support services agreement	Other Operations and Maintenance	2011	$	28		$	21		$	4		$	59		$	48		$	10
		2010		32			25			6			68			53			13
AFS support services agreement	Other Operations and Maintenance	2011		(a	)		(a	)		(a	)		(a	)		(a	)		(a	)
		2010		2			(b	)		(b	)		3			(b	)		1
Insurance premiums(c)	Other Operations and Maintenance	2011		(b	)		(a	)		-			(b	)		(a	)		-
		2010		(b	)		(a	)		-			1			(a	)		-
Total Other Operations and Maintenance Expenses		2011	$	28		$	21		$	4		$	59		$	48		$	10
		2010		34			25			6			72			53			13
Money pool borrowings (advances)	Interest Charges	2011	$	-		$	-		$	(b	)	$	-		$	-		$	(b	)
		2010		-			-			(b	)		-			-			(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.

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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.

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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 Energy Center in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at June 30, 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)
	$	12,594	(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.

(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 energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million.

(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. 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 energy center 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 energy centers, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. We have also entered into various long-term commitments for the purchase of electric capacity 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.

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Our commitments for the procurement of coal have materially increased from the amounts previously disclosed in the Form 10-K. In July 2011, Ameren Missouri entered into multi-year agreements to procure ultra low-sulfur coal and related transportation, from the Powder River Basin in Wyoming. The following table presents our total estimated coal procurement and related transportation commitments at July 19, 2011, including the July 2011 ultra low-sulfur coal and related transportation agreements:

	2011		2012		2013		2014		2015		Thereafter
Ameren	$	669	$	1,153	$	801	$	643	$	634	$	1,651
Ameren Missouri		244		618		609		630		620		1,589

Ameren’s and Ameren Illinois’ commitments for the procurement of purchased power have materially changed due to the 2011 RFP process administered by the IPA in the second quarter from amounts previously disclosed in Form 10-K as of December 31, 2010. See also Note 8 - Related Party Transactions in this report. The following table presents our total estimated purchased power commitments at June 30, 2011:

	2011		2012		2013		2014		2015		Thereafter
Ameren	$	178	$	200	$	314	$	129	$	55	$	826
Ameren Illinois		165		177		290		106		32		624

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 energy centers. 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 NO_x emissions increasing the stringency of the existing ozone national ambient air quality standard; the CSAPR, which will 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 energy centers. Within the next year, the EPA is also expected to propose NSPS and emission guidelines for greenhouse gas emissions applicable to new and existing electric generating units as well as further reductions in the annual national ambient air quality standards for ozone and fine particulates. The EPA also plans to propose an additional rule governing air pollutant transport, but has not specified when it will issue that proposal. 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 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 energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of plant assets. 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 regulation for CCR, the proposed MACT standard for the control of mercury and other hazardous air pollutants, the finalized CSAPR, and the revised national ambient air quality standards for SO₂ and NO_x emissions as of June 30, 2011. The estimates in the table below assume that CCR will continue to be regarded as nonhazardous. The estimates in the table below do not include the impacts of 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 ongoing. The estimates shown in the table below could change significantly depending upon additional federal or state requirements, regulation of greenhouse gas emissions, new hourly national ambient air quality standards or changes to existing standards for SO₂ and NO_x emissions, the final requirements under a MACT standard for the control of hazardous air pollutants such as mercury, metals, and acid gases, additional rules governing air pollutant transport, finalized regulations under the Clean Water Act, CCR being classified as hazardous, our finalized CSAPR compliance plans, new technology, variations in costs of material or labor, or alternative compliance strategies, among other factors. Ameren Missouri’s estimate in the table below includes the impacts of its July 2011 multi-year agreement to procure ultra low-sulfur coal. This change in fuel mix is estimated to eliminate or postpone past 2020, $1.1 billion of Ameren Missouri’s capital expenditures for pollution control equipment compared with the estimated capital expenditures included in the Form 10-K. In addition, the estimates for Genco and AERG in the table below have been updated from the estimates provided in the Form 10-K, based on the Merchant Generation segment’s continued optimization of environmental compliance plans.

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	2011		2012 - 2015					2016 - 2020					Total
AMO(a)	$	40	$	315	-	$	390	$	905	-	$	1,105	$	1,260	-	$	1,535
Genco		125		355	-		435		60	-		75		540	-		635
AERG		10		170	-		210		10	-		15		190	-		235
Ameren	$	175	$	840	-	$	1,035	$	975	-	$	1,195	$	1,990	-	$	2,405

(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 SO₂and 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 required generating facilities in 28 states, including Missouri and Illinois, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO₂emissions, 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 SO₂emissions 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. In July 2011, the EPA issued the CSAPR as the CAIR replacement. The CSAPR, which becomes effective on January 1, 2012, for SO₂ and annual NO_x reductions and on May 1, 2012, for ozone season NO_xreductions, replaces CAIR and its applicable state rules. In the CSAPR, the EPA developed federal implementation plans for each state covered by this rule; however, each impacted state can develop its own implementation rule starting as early as 2013. The CSAPR establishes emission allowance budgets for each of the 23 states subject to the regulation, including Missouri and Illinois. With the CSAPR, the EPA abandoned 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. For Missouri and Illinois, emission reductions are required in two phases beginning in 2012, with further reductions in 2014. The EPA estimates that by 2014, the CSAPR and other state and EPA actions will reduce SO₂ emissions from power plants by 73% and NO_x emissions by 54% from 2005 levels. With the CSAPR, the EPA adopted a cap-and-trade approach that allows intrastate and limited interstate trading of emission allowances with other sources within the same program, that is, either the SO₂, annual NO_x, or ozone season NO_xprogram. The CSAPR is voluminous and complex and our review of the finalized regulation and its impacts is ongoing. We cannot estimate at this time whether compliance with this rule will be prohibitively expensive for any of our coal-fired energy centers or if compliance with this rule will impact the expected useful lives of our coal-fired energy centers. Changes in useful life or operating cost assumptions could result in future asset impairments. Genco’s Hutsonville and Meredosia energy centers, and a unit, specifically unit one, at AERG’s E.D. Edwards energy center, are the Merchant Generation segment’s least economic coal-fired facilities and the most exposed to compliance options being prohibitively expensive. Genco’s net investment in its Hutsonville and Meredosia energy centers totaled $26 million and $1 million, respectively, and AERG’s net investment in unit one at the E.D. Edwards energy center totaled $18 million as of June 30, 2011.

Separately, in January and June 2010, the EPA finalized new ambient air 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. Ameren, Ameren Missouri and Genco continue to assess the impacts of these new standards. In July 2011, the EPA announced it is delaying the issuance of new annual national ambient air quality standards for ozone and fine particulates.

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

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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 coal-fired power plants. Also, the proposed rule requires reductions in hydrogen chloride emissions, which were not regulated previously, and may 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, SO₂and 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 late 2014. This new proposed rule is voluminous and complex, with final rules likely to be different. Ameren’s review of its impact is ongoing. We cannot at this time predict whether compliance with this rule, when finalized, would be prohibitively expensive for any of our coal-fired energy centers or if compliance with this proposed rule would impact the expected useful lives of our energy centers. Changes in useful life or operating cost assumptions could result in future asset impairments.

Ameren Missouri’s current environmental compliance plan for air emissions from its energy centers includes burning more ultra low-sulfur coal and installing new or optimizing existing pollution control equipment. The July 2011 purchase contract, as discussed in Other Obligations above, to procure significant volumes of lower sulfur-content coal than Ameren Missouri’s energy centers currently burn will allow Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment while still achieving required emissions levels. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO₂ emissions. Currently, Ameren Missouri’s compliance plan assumes the installation of two scrubbers within its coal-fired fleet during the next ten years and precipitator upgrades at multiple energy centers. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the emissions requirements set forth in the finalized CSAPR, the proposed MACT standard for mercury and other hazardous air pollutants, and other recently finalized or proposed EPA regulations.

Similarly, Ameren and Genco are currently evaluating the EPA’s finalized CSAPR and 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. Existing Illinois state regulations already required Ameren and Genco to reduce their emissions of mercury under the MPS. Based on Ameren’s and Genco’s 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, SO₂, and NO_x emissions by 2015. To comply with the MPS, Genco and AERG are installing equipment designed to reduce mercury, NO_x, and SO₂ emissions. Genco and AERG have installed a total of three scrubbers at two energy centers and preparations for the construction of two additional scrubbers are underway at a third energy center, with completion expected in late 2013 and spring 2014. Currently, Genco’s and AERG’s compliance strategies and resulting estimated environmental capital expenditures also include precipitator upgrades at Genco’s Joppa energy center and the inclusion of a baghouse and dry sorbent injection SO₂ reduction technology at AERG’s E.D. Edwards energy center. Genco and AERG may also need to install additional, or optimize existing, pollution control equipment to meet new emission reduction requirements under the MPS, CSAPR, or the proposed federal MACT standard as they become effective.

The completion of Ameren’s, Ameren Missouri’s and Genco’s review of recently finalized or proposed environmental regulations and compliance measures could result in significant increases in capital expenditures and operating costs. The compliance costs could be prohibitive at some of our energy centers as the expected return from these investments might not justify the required capital expenditures or their continued operation, which could result in the impairment of plant assets.

Emission Allowances

The Clean Air Act created marketable commodities called allowances under the acid rain program, the NO_x budget trading program, the federal CAIR, and beginning in 2012, the CSAPR. With the CSAPR, the EPA adopted a cap-and-trade approach that allows intrastate and limited interstate trading of emission allowances with other sources within the same program, that is, either the SO₂, annual NO_x, or ozone season NO_xprograms. See Note 1 - Summary of Significant Accounting Policies for the SO₂ and NO_x emission allowance book values that were classified as intangible assets as of June 30, 2011, and the impairment recorded during the three and six months ended June 30, 2011.

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Environmental regulations, including the CAIR and CSAPR, the timing of the installation of pollution control equipment, fuel mix, and the level of operations, will have a significant impact on the number of allowances required for ongoing operations. The CAIR, effective until the end of 2011, uses the acid rain program’s allowances for SO₂emissions and the NO_x budget trading program for both the annual and ozone season NO_x allowances. The CSAPR, the CAIR replacement, however, will not rely upon the acid rain program, the NO_x budget trading program, or CAIR allowances for its allowance allocation program. Instead, the EPA will issue a new type of emissions allowance for each program under the CSAPR. As a result, existing SO₂allowances may be used solely for achieving compliance with the acid rain program’s SO₂ emission limitations. Consequently, Ameren, Ameren Missouri and Genco do not expect to use all of their existing SO₂allowances for their operations. Any unused annual and ozone season NO_x allowances issued under CAIR cannot be used for compliance with CSAPR. Ameren, Ameren Missouri and Genco are analyzing the CSAPR’s SO₂and NO_x emission allowance allocations and trading restrictions.

Based on a preliminary review of the emission allowances granted under the CSAPR, Ameren, Ameren Missouri and Genco expect their 2012 allotment of allowances will exceed their emission levels for SO_2.In addition, Ameren Missouri expects its 2012 allotment of annual and ozone season NO_x emission allowances will exceed its emission levels. Conversely, the Merchant Generation segment’s expected emissions for both annual and ozone season NO_x appear to exceed its 2012 allotment. Ameren, Ameren Missouri and Genco are studying their compliance options. Ameren, Ameren Missouri and Genco may be required to purchase emission allowances, if available, install new or optimize existing pollution control equipment, limit generation, or take other actions, including the potential closure of energy centers, to achieve compliance with the CSAPR.

Global Climate Change

Initiatives to limit greenhouse gas emissions and to address climate change have been subject to consideration in the U.S. Congress. Since 2009, 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 was 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 energy centers, 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 energy centers 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

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technology if their greenhouse gas emissions exceed the applicable emissions threshold. Separately, in December 2010, the EPA announced it would establish NSPS for greenhouse gas emissions at new and existing fossil fuel-fired power plants. The EPA has extended its deadline to issue its proposed standard for power plants, called the performance standard, until the end of September 2011, with final standards expected in 2012. It is uncertain whether reductions to greenhouse gas emissions would be required at Ameren’s, Ameren Missouri’s or Genco’s energy centers 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 energy centers 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 energy centers, 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 United States House of Representatives and 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 United States House of Representatives and 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 earlier than planned, which 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.

Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change. In June 2011, the United States Supreme Court inState of Connecticut v. American Electric Power rejected state efforts to impose liability for CO₂ and greenhouse gases emissions under federal common law. That ruling, however, did not address whether private citizens could pursue causes of action based on state common law. In June 2011, litigation was filed in the United States District Court for the Southern District of Mississippi namedComer v. Murphy Oil(Comer), where a Mississippi property owner sued several industrial companies, including Ameren Missouri and Genco, alleging that CO₂ emissions created the atmospheric conditions that intensified Hurricane Katrina. While we are unable to predict the outcome of the Comer litigation on our results of operations, financial position, and liquidity, Ameren believes that it has meritorious defenses. Numerous procedural and substantive challenges are expected in the Comer litigation.

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 energy centers 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 energy centers and AERG’s E.D. Edwards and Duck Creek energy centers. In 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton energy center. All of these facilities are coal-fired energy centers. In September 2008, the EPA issued a third Section 114(a) request regarding projects at all of Ameren’s coal-fired energy centers in Illinois. We completed our response to the information requests, but we are unable to predict the outcome of this matter.

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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 energy centers, 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 energy centers. In January 2011, the Department of Justice on behalf of 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 energy center, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In June 2011, following the filing of motions to dismiss by Ameren Missouri, the Department of Justice amended its lawsuit to include additional Rush Island projects and to correct deficiencies in the initial complaint. At present, the complaint does not include Ameren Missouri’s other coal-fired energy centers. 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.

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 pollution control equipment, 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 energy centers 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 Ameren Illinois 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, Ameren Illinois has contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of June 30, 2011, Ameren and Ameren Illinois 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 Ameren Illinois could substantially conclude remediation efforts at most of these sites by 2015. The ICC permits Ameren Illinois 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.

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As of June 30, 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 June 30, 2011, the estimated probable obligation to remediate these MGP sites.

	Estimate
	Low		High		Recorded    Liability(a)
Ameren	$	121	$	199	$	121
Ameren Missouri		3		4		3
Ameren Illinois		118		195		118

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

Ameren Illinois is responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of June 30, 2011, Ameren Illinois estimated that obligation at $0.5 million to $6 million. Ameren Illinois 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. Ameren Illinois is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of June 30, 2011, Ameren Illinois 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 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 June 30, 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 equipment 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 June 30, 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 an energy center 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, if any, it would 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 June 30, 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 energy center. In 2010, AERG closed the recycle pond system. Remediation work on the recycle pond was completed in the first quarter of 2011, and therefore no liability exists as of June 30, 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 energy centers.

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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 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 Pollution Control Board approved a site-specific plan for the closure of an ash pond at Genco’s Hutsonville energy center. 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 energy center, similar to the approved plan for Hutsonville. Similar closure requirements and groundwater management plans for ash ponds at the Duck Creek energy center 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 Energy Center Breach

In December 2005, there was a breach of the upper reservoir at Ameren Missouri’s Taum Sauk pumped-storage hydroelectric energy center. 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. The rebuilt Taum Sauk energy center became fully operational in April 2010.

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 June 30, 2011. As of June 30, 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 June 30, 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, seeking the ability to pursue resolution of this dispute outside of a dispute resolution process under the terms of its coverage agreement.

Until Ameren’s remaining liability insurance claims and the related litigation are resolved, 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. Ameren Missouri included certain capitalized costs associated with enhancements, or costs that could have been incurred absent the breach, at the rebuilt Taum Sauk energy center not recovered from property insurers in its recently completed electric rate case. However, in the July 2011 rate order, the MoPSC disallowed all of the capitalized costs associated with the rebuilding of the Taum Sauk energy center. As a result of the order, Ameren and Ameren Missouri will each record, in the third quarter ending September 30, 2011, a pretax charge to earnings of $89 million to reflect this disallowance. See Note 2 - Rate and Regulatory Matters for additional information about the MoPSC’s July 2011 electric rate order.

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Asbestos-related Litigation

Ameren, Ameren Missouri, Ameren Illinois 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 June 30, 2011, the average number of parties was 78.

The claims filed against Ameren, Ameren Missouri, Ameren Illinois and Genco allege injury from asbestos exposure during the plaintiffs’ activities at our present or former energy centers. Former CIPS energy centers are now owned by Genco, and former CILCO energy centers are now owned by AERG. As a part of the transfer of ownership of the CIPS and CILCO energy centers, CIPS and CILCO, now Ameren Illinois, 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.

The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of June 30, 2011:

Ameren	AMO	AIC	Genco	Total(a)
5	54	74	(b)	95

(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 June 30, 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 June 30, 2011, Ameren, Ameren Missouri, Ameren Illinois and Genco had liabilities of $19 million, $7 million, $12 million, and $- million, respectively, recorded to represent their best estimate of their obligations related to asbestos claims.

Ameren Illinois 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 June 30, 2011, the trust fund balance was approximately $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois 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 Ameren Illinois 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

InExelon 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 June 30, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $19 million and $13 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.

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NOTE 10 - CALLAWAY ENERGY CENTER

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 energy center. 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 energy center until 2020. It has the capability for additional storage capacity through the licensed life of the energy center. 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 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 will be only advisory and its draft report was submitted on July 29, 2011. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway energy center through its currently licensed life.

In 1984, the DOE entered into a contract with Ameren Missouri to dispose of nuclear waste from its Callaway energy center. 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 filed suit in 2004 to recover approximately $13 million in costs that it incurred through 2009. This amount included the cost of reracking the Callaway energy center’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. In December 2010, Ameren Missouri and DOE began investigating settlement options, and in June 2011 the parties reached a settlement. The terms of the settlement include payment to Ameren Missouri of approximately $11 million for spent fuel storage and related costs through 2010, and thereafter, annual payment of such costs after they are incurred through 2013 or any other mutually agreed extension. As a result of this settlement agreement, Ameren Missouri recorded a pretax reduction of $2 million and $2 million to its depreciation and amortization and other operations and maintenance line items, respectively, on its statement of income for the three and six months ended June 30, 2011. Ameren Missouri reduced its property and plant assets by $7 million. Ameren Missouri received the DOE settlement amount in July 2011. Under the settlement, Ameren Missouri’s breach of contract suit will be dismissed.

Ameren Missouri intends to submit a license extension application with the NRC to extend its Callaway energy center’s operating license from 2024 to 2044. If the Callaway energy center’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 energy center and intends to begin transferring spent fuel assemblies to this facility prior to 2020.

Electric utility rates charged to customers provide for the recovery of the Callaway energy center’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the nuclear center, ending with the expiration of the energy center’s operating license in 2024. It is assumed that the Callaway energy center 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 energy center 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 energy center. Electric rates

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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 energy center site, which did not result in a significant increase in the decommissioning cost estimate. Ameren Missouri expects to file a new cost study in the third quarter of 2011. Amounts collected from customers are deposited in an external trust fund to provide for the Callaway energy center’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 energy center 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 or regulatory liability.

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 and six months ended June 30, 2011 and 2010 is shown below for Ameren, Ameren Illinois and Genco. Ameren Missouri’s comprehensive income was composed only of its net income for the three and six months ended June 30, 2011 and 2010.

	Three Months						Six Months
	2011			2010			2011			2010
Ameren:(a)
Net income	$	139		$	155		$	213		$	261
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(5), $(7), $(4), and $11, respectively		(8	)		(11	)		(6	)		17
Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $(4), $3, $(2), and $12, respectively		7			(5	)		3			(20	)
Pension and other postretirement activity, net of income taxes (benefit) of $(1), $5, $(2), and $6, respectively		-			7			(1	)		6
Total comprehensive income, net of taxes	$	138		$	146		$	209		$	264
Less: Net income attributable to noncontrolling interests, net of taxes		1			3			4			7
Total comprehensive income attributable to Ameren Corporation, net of taxes	$	137		$	143		$	205		$	257
Ameren Illinois:
Net income	$	38		$	57		$	72		$	105
Pension and other postretirement activity, net of income taxes (benefit) of $(1), $- , $(1), and $- , respectively		(1	)		-			(2	)		(1	)
Total comprehensive income, net of taxes	$	37		$	57		$	70		$	104
Genco:
Net income	$	13		$	14		$	35		$	38
Pension and other postretirement activity, net of income taxes (benefit) of $1, $3 , $1, and $5 , respectively		-			5			1			4
Total comprehensive income, net of taxes	$	13		$	19		$	36		$	42
Less: Net income attributable to noncontrolling interest, net of taxes		-			1			1			2
Total comprehensive income attributable to Genco	$	13		$	18		$	35		$	40

(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 net periodic cost for regulatory purposes or the legally required minimum contribution. Considering Ameren’s assumptions at December 31, 2010, its estimated investment performance through June 30, 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 net periodic cost for regulatory purposes.

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The following table presents the components of the net periodic benefit cost for Ameren’s pension and postretirement benefit plans for the three and six months ended June 30, 2011, and 2010:

	Pension Benefits(a)												Postretirement Benefits(a)
	Three Months						Six Months						Three Months						Six Months
	2011			2010			2011			2010			2011			2010			2011			2010
Service cost	$	18		$	16		$	38		$	33		$	5		$	5		$	11		$	10
Interest cost		45			46			90			93			14			14			29			30
Expected return on plan assets		(54	)		(53	)		(108	)		(106	)		(13	)		(14	)		(27	)		(28	)
Amortization of:
Transition obligation		-			-			-			-			1			1			1			1
Prior service cost (benefit)		(1	)		2			(1	)		4			(2	)		(2	)		(4	)		(4	)
Actuarial loss (gain)		10			4			21			9			1			(1	)		2			1
Net periodic cost	$	18		$	15		$	40		$	33		$	6		$	3		$	12		$	10

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

Ameren Missouri, Ameren Illinois 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 and six months ended June 30, 2011, and 2010:

	Pension Costs								Postretirement Costs
	Three Months				Six Months				Three Months				Six Months
	2011		2010		2011		2010		2011		2010		2011		2010
Ameren Missouri	$	12	$	9	$	26	$	21	$	2	$	2	$	5	$	5
Ameren Illinois		3		4		8		6		4		1		6		4
Genco		3		2		5		5		-		-		1		1
Other		-		-		1		1		-		-		-		-
Ameren(a)	$	18	$	15	$	40	$	33	$	6	$	3	$	12	$	10

(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 Regulated Segment for Ameren includes all of the operations of Ameren Illinois’ 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.

The following table presents information about the reported revenues and specified items included in Ameren’s net income for the three and six months ended June 30, 2011, and 2010, and total assets as of June 30, 2011, and December 31, 2010.

Three Months	Ameren Missouri		Ameren Illinois Regulated		Merchant Generation			Other			Intersegment Eliminations			Consolidated
2011:
External revenues	$	814	$	619	$	347		$	1		$	-		$	1,781
Intersegment revenues		8		4		49			-			(61	)		-
Net income (loss) attributable to Ameren Corporation(a)		90		37		15			(4	)		-			138
2010:
External revenues	$	756	$	644	$	325		$	-		$	-		$	1,725
Intersegment revenues		5		3		60			3			(71	)		-
Net income (loss) attributable to Ameren Corporation(a)		113		46		(2	)		(5	)		-			152
Six Months
2011:
External revenues	$	1,581	$	1,424	$	679		$	1		$	-		$	3,685
Intersegment revenues		13		7		96			1			(117	)		-
Net income (loss) attributable to Ameren Corporation(a)		111		70		35			(7	)		-			209
2010:
External revenues	$	1,433	$	1,553	$	679		$	-		$	-		$	3,665
Intersegment revenues		10		5		134			6			(155	)		-
Net income (loss) attributable to Ameren Corporation(a)		140		81		42			(9	)		-			254
As of June 30, 2011:
Total assets	$	12,527	$	7,154	$	3,861		$	1,324		$	(1,475	)	$	23,391
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.

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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 Ameren Illinois Merger. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company.

Ameren Illinois 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, Ameren Illinois 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 Ameren Illinois’ former merchant generation subsidiary, AERG, classified as discontinued operations in Ameren Illinois’ statement of income for the three and six months ended June 30, 2010:

	2010
	Three Months		Six Months
Operating revenues	$	85	$	176
Operating expenses		67		134
Operating income		18		42
Other income		1		1
Interest charges		5		10
Income taxes		5		12
Income from discontinued operations, net of tax	$	9	$	21

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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 second quarter and the first six months of 2011 were lower compared with its earnings in the second quarter and first six months of 2010. Ameren’s earnings were lower during these periods because of reduced margins in Ameren’s Merchant Generation segment as a result of lower power prices and higher fuel and related transportation costs, increased storm costs for the Ameren Missouri and Ameren Illinois business segments, and the impact of milder weather and the weak economy on Ameren’s utility sales. Additionally, earnings were lower in the second quarter and the first six months of 2011, compared to the prior-year periods, because of lower capitalized financing costs and a charge to earnings resulting from an April 2011 MoPSC requirement that certain revenues and costs be included in Ameren Missouri’s FAC. Factors that favorably contributed to second quarter and the first six months of 2011 earnings, compared to 2010 earnings for both periods, included the absence of a nuclear refueling and maintenance outage at Ameren Missouri’s Callaway energy center, electric rate increases in Missouri and Illinois effective in 2010, a gas delivery rate increase in Missouri effective in early 2011, lower interest expense, and favorable net MTM activity on Ameren’s nonqualified power and fuel-related hedges. Also benefiting earnings for the first six months of 2011 was the absence in 2011 of recording the effect of changes in federal healthcare laws that were enacted in 2010.

The EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry, especially those that operate coal-fired energy centers. In July 2011, the EPA issued the CSAPR. This rule requires significant reductions in SO₂ and NO_x emissions beginning in 2012, with additional reductions required in 2014. The CSAPR standards for reduced SO₂ emissions were in line with the rules Ameren expected the EPA to adopt, but the standards for reduced NO_x emissions were more stringent than expected. The CSAPR is voluminous and complex and Ameren’s review of the finalized regulation and its impacts is ongoing.

Ameren, Ameren Missouri and Genco have proactively worked to reduce their emissions of both SO₂ and NO_x in innovative and cost effective ways, to improve air quality, and keep generation costs low. In addition to burning low-sulfur coal, Ameren, Ameren Missouri and Genco have installed pollution control equipment, in advance of the CSAPR, which has reduced their SO₂ and NO_x emissions. In July 2011, Ameren Missouri entered into a coal contract for the purchase of approximately 90 million tons of ultra low-sulfur coal to be delivered between 2012 and 2017. Ameren Missouri also entered into additional rail transportation contracts to deliver coal supplied under the new coal purchase contract through 2017. This strategy will allow Ameren Missouri to delay the installation of additional scrubbers until after 2017. As a result of this strategy, Ameren Missouri was able to reduce its planned capital expenditures for the period 2011 to 2015 by approximately $500 million, compared to the estimates provided in the Form 10-K. While this strategy has significant benefits, it only addresses the SO₂ component of the CSAPR for Ameren Missouri. Ameren Missouri is evaluating multiple alternatives for complying with CSAPR’s NO_x emission standards. Ameren’s Merchant Generation segment and Genco are evaluating multiple alternatives for complying with CSAPR’s NO_x emission standards, though a material increase in current estimated capital expenditures through 2015 is not expected. Merchant Generation and Genco were already planning reductions in SO₂ and NO_x emissions because of the MPS. As a result of continued optimization of environmental compliance plans and reductions of discretionary non-environmental spending, the Merchant Generation segment reduced its 2011 to 2015 planned capital expenditures by approximately $200 million, compared to the estimates provided in the Form 10-K.

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Also in July 2011, the MoPSC issued a decision on Ameren Missouri’s electric rate case authorizing a $173 million annual rate increase. This order included in rates Ameren Missouri’s full investment in the Sioux scrubbers and related operating costs and property taxes. The MoPSC disallowed all of the costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance. As a result of the order, Ameren and Ameren Missouri each will record a pretax charge to earnings of $89 million relating to the Taum Sauk disallowance in the third quarter ending September 30, 2011. Ameren Missouri has appealed this disallowance to the courts. Separately, in July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren Missouri to defer, as a regulatory asset, fixed costs totaling $36 million not recovered from Noranda as a result of the loss of load caused by a severe 2009 ice storm for potential recovery in a future electric rate case.

Ameren Illinois filed rebuttal testimony in its pending rate case requesting a $90 million annual increase in electric and natural gas delivery service rates. Ameren Illinois’ rate case is based on a 2012 test year to provide an improved opportunity to earn a fair return on investment. Additionally, Ameren Illinois continues to support the advancement of the Illinois Energy Infrastructure Modernization Act, which passed both chambers of the Illinois General Assembly in late May 2011.

Ameren Missouri and Ameren Illinois plan to take appropriate actions to align their overall spending, both operating and capital, to be consistent with regulatory outcomes and the related cash flows provided by those decisions. Consequently, Ameren’s rate-regulated operations expect to make progress towards narrowing the gap between allowed and earned returns on equity.

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.

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

• Resources Company consists of non-rate-regulated operations, including Genco, AERG, Marketing Company and Medina Valley. Genco operates a merchant electric generation business in Illinois. 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 Ameren Illinois Merger. Upon consummation of the Ameren Illinois Merger, the separate legal existence of CILCO and IP terminated. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. The Ameren Illinois 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 Ameren Illinois included purchase accounting adjustments related to Ameren’s acquisition of CILCORP in 2003. Ameren Illinois accounted for the AERG distribution as a spinoff. Ameren Illinois transferred AERG to Ameren based on AERG’s carrying value. Ameren Illinois has segregated AERG’s operating results and cash flows and presented them

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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 natural gas delivery service businesses, a purchased power cost recovery mechanism for our Illinois electric delivery service business, and a FAC for our Missouri electric utility business. 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 energy centers 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 $138 million, or 57 cents per share, in the second quarter of 2011, from $152 million, or 64 cents per share, in the second quarter of 2010. Net income attributable to Ameren Corporation in the second quarter of 2011 declined in the Ameren Missouri segment and Ameren Illinois Regulated Segment by $23 million and $9 million, respectively, from the prior-year period. Net income attributable to Ameren Corporation in the second quarter of 2011 increased in the Merchant Generation segment by $17 million from the prior-year period.

Net income attributable to Ameren Corporation decreased to $209 million, or 87 cents per share, in the first six months of 2011 from $254 million, or $1.07 per share, in the first six months of 2010. Net income attributable to Ameren Corporation in the first six months of 2011 declined in the Ameren Missouri segment, Ameren Illinois Regulated Segment and Merchant Generation segment by $29 million, $11 million, and $7 million, respectively, from the prior-year period.

Earnings were negatively impacted in the second quarter and first six months of 2011, compared with the same periods in 2010, by:

• increased operations and maintenance expenses as a result of major storms in 2011 (4 cents per share and 9 cents per share, respectively);

• lower realized electric margins in the Merchant Generation segment, largely due to lower production volumes, lower realized revenue per megawatthour sold, and higher fuel and related transportation costs (2 cents per share and 9 cents per share, respectively). This amount excludes the favorable impacts of net unrealized MTM activity discussed below. See Outlook for expected trends in future coal, transportation and power prices;

• the impact of weather conditions in 2011 on electric demand (estimated at 5 cents per share and 7 cents per share, respectively);

• the unfavorable impact on electric and natural gas margins in our rate-regulated businesses from reduced rate-regulated retail sales volumes, excluding the effects of abnormal weather, as well as lower wholesale sales at Ameren Missouri due to a reduction in customers and the expiration of favorably priced contracts, among other things (4 cents per share and 6 cents per share, respectively);

• an increase in property taxes, primarily at Ameren Missouri, due to higher assessments and rates, and the impact on Ameren’s effective tax rate caused in part by an increase in the state of Illinois statutory income tax rate, excluding the impact on deferred taxes from changes in federal health care laws discussed separately below (4 cents per share and 6 cents per share);

• a reduction in revenues resulting from the MoPSC’s order with respect to its FAC prudence review for the period from March 1, 2009, to September 30, 2009, that resulted in Ameren Missouri recording an obligation to refund to its electric customers the earnings associated with certain sales previously recognized by Ameren Missouri. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, for additional information (5 cents per share in both periods); and

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• a reduction in allowance for equity funds used during construction reflecting the 2010 completion of two scrubbers at Ameren Missouri’s Sioux energy center (2 cents per share and 5 cents per share, respectively).

Earnings were favorably impacted in the second quarter and first six months of 2011, compared with the same periods in 2010, by:

• a reduction in costs at our energy centers caused by the absence of a scheduled nuclear refueling and maintenance outage at the Callaway energy center, which occurred during the spring of 2010, partially offset by an increase in costs from outages at coal-fired energy centers (8 cents per share and 9 cents per share);

• higher Ameren Missouri and Ameren Illinois electric rates pursuant to orders issued by the MoPSC and the ICC, respectively, in 2010, and higher Ameren Missouri natural gas rates pursuant to a MoPSC January 2011 order. The impact of the Ameren Missouri electric rate increase on earnings was reduced by the adoption of the life span depreciation methodology, recognition in 2010 of regulatory assets for previously-expensed costs in the prior-year period, and increased regulatory asset amortization as directed by the rate order (4 cents per share and 7 cents per share, respectively);

• lower interest expense primarily due to the maturity and repayment of $200 million of Genco’s senior secured notes in November 2010, the redemption of $66 million of Ameren Missouri’s subordinated deferrable interest debentures in September 2010, and a reduction in borrowings under credit facility agreements (3 cents per share and 7 cents per share, respectively); and

• a reduction in the loss between years from net MTM activity primarily related to nonqualifying power hedges for the quarter and an increased gain between years from net unrealized MTM activity on fuel-related contracts for the six month period (7 cents per share and 3 cents per share).

In addition to the above items affecting both periods, earnings were favorably impacted in the first six months of 2011, compared with the same period in 2010, by the absence in 2011 of a charge for the impact on deferred taxes from changes in federal health care laws (6 cents per share).

The cents per share information presented above is based on average shares outstanding in the second quarter and first six months of 2010, respectively. For further details regarding the Ameren Companies’ results of operations for the second quarter and first six months of 2011, 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 subsidiaries. The following table presents the contribution by Ameren’s registrant subsidiaries to net income attributable to Ameren Corporation for the three and six months ended June 30, 2011, and 2010:

	Three Months						Six Months
	2011			2010			2011			2010
Net income (loss):
Ameren Missouri	$	90		$	113		$	111		$	140
Ameren Illinois		37			55			70			102
Genco		13			13			34			36
Other(a)		(2	)		(29	)		(6	)		(24	)
Net income attributable to Ameren Corporation	$	138		$	152		$	209		$	254

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

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Below is a table of income statement components for Ameren’s segments for the three and six months ended June 30, 2011, and 2010:

	Ameren   Missouri			Ameren   Illinois     Regulated			Merchant   Generation			Other /   Intersegment   Eliminations			Total
Three Months 2011:
Electric margin	$	561		$	287		$	161		$	(3	)	$	1,006
Natural gas margin		17			72			-			(1	)		88
Other revenues		3			1			1			(5	)		-
Other operations and maintenance expenses		(231	)		(181	)		(76	)		13			(475	)
Depreciation and amortization expenses		(98	)		(54	)		(37	)		(5	)		(194	)
Taxes other than income taxes		(76	)		(26	)		(5	)		(2	)		(109	)
Other income and (expenses)		13			-			-			(1	)		12
Interest charges		(45	)		(35	)		(25	)		1			(104	)
Income (taxes) benefit		(53	)		(26	)		(4	)		(2	)		(85	)
Net income (loss)		91			38			15			(5	)		139
Noncontrolling interest and preferred dividends		(1	)		(1	)		-			1			(1	)
Net income (loss) attributable to Ameren Corporation	$	90		$	37		$	15		$	(4	)	$	138
Three Months 2010:
Electric margin	$	583		$	270		$	148		$	(3	)	$	998
Natural gas margin		13			77			-			-			90
Other revenues		1			-			-			(1	)		-
Other operations and maintenance expenses		(240	)		(159	)		(69	)		3			(465	)
Depreciation and amortization expenses		(92	)		(52	)		(37	)		(9	)		(190	)
Taxes other than income taxes		(68	)		(24	)		(7	)		(3	)		(102	)
Other income		19			1			1			1			22
Interest charges		(43	)		(34	)		(35	)		(3	)		(115	)
Income (taxes) benefit		(58	)		(31	)		(2	)		8			(83	)
Net income (loss)		115			48			(1	)		(7	)		155
Noncontrolling interest and preferred dividends		(2	)		(2	)		(1	)		2			(3	)
Net income (loss) attributable to Ameren Corporation	$	113		$	46		$	(2	)	$	(5	)	$	152
Six Months 2011:
Electric margin	$	1,014		$	518		$	343		$	(5	)	$	1,870
Natural gas margin		46			190			-			(2	)		234
Other revenues		4			1			2			(7	)		-
Other operations and maintenance expenses		(464	)		(349	)		(147	)		22			(938	)
Depreciation and amortization expenses		(198	)		(106	)		(73	)		(12	)		(389	)
Taxes other than income taxes		(149	)		(67	)		(13	)		(5	)		(234	)
Other income and (expenses)		23			1			-			(1	)		23
Interest charges		(99	)		(70	)		(53	)		(1	)		(223	)
Income (taxes) benefit		(64	)		(46	)		(23	)		3			(130	)
Net income (loss)		113			72			36			(8	)		213
Noncontrolling interest and preferred dividends		(2	)		(2	)		(1	)		1			(4	)
Net income (loss) attributable to Ameren Corporation	$	111		$	70		$	35		$	(7	)	$	209
Six Months 2010:
Electric margin	$	1,022		$	502		$	375		$	(10	)	$	1,889
Natural gas margin		42			201			-			(1	)		242
Other revenues		1			-			-			(1	)		-
Other operations and maintenance expenses		(458	)		(321	)		(142	)		19			(902	)
Depreciation and amortization expenses		(184	)		(106	)		(73	)		(14	)		(377	)
Taxes other than income taxes		(136	)		(66	)		(15	)		(6	)		(223	)
Other income and (expenses)		38			-			1			(2	)		37
Interest charges		(102	)		(71	)		(69	)		(5	)		(247	)
Income (taxes) benefit		(80	)		(55	)		(33	)		10			(158	)
Net income (loss)		143			84			44			(10	)		261
Noncontrolling interest and preferred dividends		(3	)		(3	)		(2	)		1			(7	)
Net income (loss) attributable to Ameren Corporation	$	140		$	81		$	42		$	(9	)	$	254

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Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and natural gas margins in the three and six months ended June 30, 2011, compared with the same periods 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			AMO			AIC			Genco			Other(a)
Electric revenue change:
Effect of weather (estimate)(b)	$	(20	)	$	(17	)	$	(3	)	$	-		$	-
Regulated rates:
Higher base rates		60			53			7			-			-
Recovery of FAC under-recovery		31			31			-			-			-
Off-system revenues		39			39			-			-			-
FAC prudence review disallowance 71		(17	)		(17	)		-			-			-
Transmission services		17			3			13			-			1
Illinois pass-through power supply costs		(21	)		-			(31	)		-			10
Energy efficiency programs and environmental remediation cost riders		12			-			12			-			-
Bad debt rider		(4	)		-			(4	)		-			-
Rate-regulated sales (excluding the impact of abnormal weather)		(33	)		(26	)		(7	)		-			-
Wholesale revenues		(13	)		(13	)		-			-			-
Merchant sales price changes, including hedge effect		13			-			-			5			8
Net unrealized MTM gains (losses)		23			-			-			(2	)		25
Non-rate-regulated sales and other		(25	)		1			(1	)		(18	)		(7	)
Total electric revenue change	$	62		$	54		$	(14	)	$	(15	)	$	37
Fuel and purchased power change:
Fuel:
Production volume and other	$	22		$	4		$	-		$	14		$	4
FAC under-recovery(c)		(65	)		(65	)		-			-			-
Recovery of FAC under-recovery		(31	)		(31	)		-			-			-
Net unrealized MTM losses		(3	)		-			-			(2	)		(1	)
Price - Merchant Generation		(8	)		-			-			(6	)		(2	)
Purchased power		10			16			-			-			(6	)
Illinois pass-through power supply costs		21			-			31			-			(10	)
Total fuel and purchased power change	$	(54	)	$	(76	)	$	31		$	6		$	(15	)
Net change in electric margins	$	8		$	(22	)	$	17		$	(9	)	$	22
Natural gas margins change:
Effect of weather (estimate)(b)	$	2		$	-		$	2		$	-		$	-
Bad debt rider		(4	)		-			(4	)		-			-
Change in base rates		2			1			1			-			-
Energy efficiency programs and environmental remediation cost riders		2			-			2			-			-
Sales (excluding impact of abnormal weather) and other		(4	)		3			(6	)		-			(1	)
Net change in natural gas margins	$	(2	)	$	4		$	(5	)	$	-		$	(1	)
Six Months
Electric revenue change:
Effect of weather (estimate)(b)	$	(27	)	$	(22	)	$	(5	)	$	-		$	-
Regulated rates:
Higher base rates		112			102			10			-			-
Recovery of FAC under-recovery		71			71			-			-			-
Off-system revenues		60			60			-			-			-
FAC prudence review disallowance		(17	)		(17	)		-			-			-
Transmission services		22			4			17			-			1
Illinois pass-through power supply costs		(52	)		-			(89	)		-			37
Energy efficiency programs and environmental remediation cost riders		12			-			12			-			-
Bad debt rider		(6	)		-			(6	)		-			-
Rate-regulated sales (excluding impact of abnormal weather)		(34	)		(24	)		(10	)		-			-
Wholesale revenues		(31	)		(31	)		-			-			-
Merchant sales price changes, including hedge effect		1			-			-			(4	)		5
Reduction in net unrealized MTM gains		(12	)		(1	)		-			(3	)		(8	)
Non-rate-regulated sales and other		(22	)		7			(2	)		(34	)		7
Total electric revenue change	$	77		$	149		$	(73	)	$	(41	)	$	42

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Six Months	Ameren			AMO			AIC			Genco			Other(a)
Fuel and purchased power change:
Fuel:
Production volume and other	$	12		$	(18	)	$	-		$	21		$	9
FAC under-recovery(c)		(108	)		(108	)		-			-			-
Recovery of FAC under-recovery		(71	)		(71	)		-			-			-
Net unrealized MTM gains		17			-			-			13			4
Price - Merchant Generation		(21	)		-			-			(16	)		(5	)
Purchased power		23			40			-			2			(19	)
Illinois pass-through power supply costs		52			-			89			-			(37	)
Total fuel and purchased power change	$	(96	)	$	(157	)	$	89		$	20		$	(48	)
Net change in electric margins	$	(19	)	$	(8	)	$	16		$	(21	)	$	(6	)
Natural gas margins change:
Bad debt rider	$	(5	)	$	-		$	(5	)	$	-		$	-
Change in base rates		2			2			-			-			-
Energy efficiency programs and environmental remediation cost riders		(1	)		-			(1	)		-			-
Sales (excluding impact of abnormal weather) and other		(4	)		2			(5	)		-			(1	)
Net change in natural gas margins	$	(8	)	$	4		$	(11	)	$	-		$	(1	)

(a) Includes amounts for nonregistrant subsidiaries (largely made up of other Merchant Generation) 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 period based on temperature readings from the National Oceanic and Atmospheric Administration.

(c) Represents the change in net base fuel cost rates incorporated and recovered in base rate revenues between years.

Ameren

Ameren’s electric margins increased by $8 million, or 1%, for the three months ended June 30, 2011, compared with the same period in 2010; however, electric margins decreased by $19 million, or 1%, for the six months ended June 30, 2011, compared with the same period in 2010. The following items had an unfavorable impact on Ameren’s electric margins for the three and six months ended June 30, 2011, compared with the year-ago periods:

• Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes declined 2% and 1%, respectively, attributable to continued economic pressure, energy efficiency measures and customer conservation efforts ($33 million and $34 million, respectively).

• Lower wholesale sales at Ameren Missouri due to a reduction in customers and expiration of favorably priced contracts ($13 million and $31 million, respectively).

• Unfavorable weather conditions, as evidenced by a 13% and 12% decrease compared to year-ago periods in cooling degree-days, respectively ($20 million and $27 million, respectively). Weather conditions in Ameren’s service territory were warmer than normal as evidenced by a 20% increase compared to normal in cooling degree-days for the quarter and year-to-date periods.

• 6% and 7% higher fuel prices for the quarter and year-to-date periods, respectively, in the Merchant Generation segment, primarily due to higher commodity and transportation costs associated with new supply contracts ($8 million and $21 million, respectively).

• A reduction in revenues at Ameren Missouri resulting from the MoPSC’s order with respect to its FAC prudence review disallowance for the period from March 1, 2009, to September 30, 2009 ($17 million and $17 million, respectively). See Note 2 – Rate and Regulatory Matters under Part 1, Item 1 for further information regarding the FAC prudence review.

• Decrease in recovery of prior years’ bad debt expense through the Illinois bad debt rider at Ameren Illinois, which became effective March 2010 ($4 million and $6 million, respectively). 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 impact on Ameren’s electric margins for the three and six months ended June 30, 2011, compared with the year-ago periods:

• Higher electric base rates at Ameren Missouri, effective June 2010 ($53 million and $102 million, respectively), offset by increased net base fuel expense ($6 million and $26 million, respectively), which was a result of higher net base fuel cost rates approved in the 2010 MoPSC rate order. Net base fuel expense is the sum of fuel - production volume and other (+$4 million and -$18 million, respectively), purchased power (+$16 million and +$40 million, respectively), and off-system revenues (+$39 million and +$60 million, respectively) offset by the FAC under-recovery (-$65 million and -$108 million, respectively). See below for additional details regarding the FAC.

• Higher transmission revenues primarily associated with higher FERC-regulated transmission rates ($17 million and $22 million, respectively). Higher rates were due, in part, to a significant increase in transmission assets placed into service at Ameren Illinois, higher equity levels as a result of Ameren’s capital contributions to Ameren Illinois, and mild 2009 weather, which all impacted the FERC transmission rates that became effective in the second quarter of 2010.

• Increase in recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms at Ameren Illinois ($12 million and $12 million, respectively). See Operations and Maintenance in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.

• Higher electric delivery service rates at Ameren Illinois, effective in early May 2010 and November 2010 ($7 million and $10 million, respectively).

• Net unrealized MTM activity principally at the Merchant Generation segment (primarily at Marketing Company), largely related to nonqualifying power hedges, partially offset by fuel-related contracts for the quarter. However, the year-to-date activity was primarily driven by financial

65

instruments acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts, partially offset by nonqualifying power hedges ($20 million and $5 million, respectively).

• Net favorable sales price changes due to a settlement of a contract dispute with a large customer in the second quarter, which mitigated lower sales prices. Sales prices were lower 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 ($13 million and $1 million, respectively).

Ameren’s Illinois pass-through power supply costs reflected lower power prices on sales primarily made with nonaffiliated parties. As a result, these revenues were offset by a corresponding net decrease in purchased power costs ($21 million and $52 million, respectively).

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, fuel and purchased power costs that were greater than the amount set in base rates (FAC under-recovery). However, as a result of the higher net base fuel cost rates authorized in the 2010 MoPSC rate order, Ameren Missouri had a lower amount of under-recovered fuel costs to accrue as regulatory asset for the three and six months ended June 30, 2011, which resulted in an unfavorable impact on FAC under-recovery of $65 million and $108 million, respectively. Under the FAC, the change in net recovery of fuel costs from its customers was $31 million and $71 million, respectively, for the three and six months ended June 30, 2011, with corresponding offsets 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 by $2 million, or 2%, and $8 million, or 3%, for the three and six months ended June 30, 2011, respectively, compared with the same periods in 2010. The following items had an unfavorable impact on Ameren’s natural gas margins for the three and six months ended June 30, 2011, compared with the year-ago periods (except where a specific period is referenced):

• Decrease in recovery of prior years’ bad debt expense through the Illinois bad debt rider at Ameren Illinois, which became effective March 2010 ($4 million and $5 million, respectively). See Operations and Maintenance in this section for additional information on a related offsetting decrease in bad debt expense.

• Decrease in recovery of energy efficiency and environmental remediation costs through Illinois rate-adjustment mechanisms at Ameren Illinois of $1 million for the year-to-date period; however, there was an increase of $2 million for the second quarter. See Operations and Maintenance in this section for information on a related offsetting decrease in energy efficiency program costs and environmental remediation costs.

• 14% and 5% lower sales volumes, respectively, excluding the estimated impact of abnormal weather, largely in the commercial and industrial sectors, attributable to continued economic pressure ($4 million and $4 million, respectively).

The following items had a favorable impact on Ameren’s natural gas margins for the three and six months ended June 30, 2011, compared with the year-ago periods:

• Higher natural gas rates effective February 2011 at Ameren Missouri (less than $1 million and $2 million, respectively).

• Favorable weather conditions, as evidenced by a 64% and 1% increase compared to year-ago periods in heating degree-days, respectively ($2 million and less than $1 million, respectively). Compared to normal, Ameren experienced a 2% decline and 6% increase in heating degree-days for the quarter and year-to-date periods, respectively.

Ameren Missouri

Ameren Missouri has a FAC cost recovery mechanism as discussed under Ameren above.

Ameren Missouri’s electric margins decreased by $22 million, or 4%, and $8 million, or 1%, for the three and six months ended June 30, 2011, respectively, compared with the same periods in 2010. The following items had an unfavorable impact on Ameren Missouri’s electric margins for the three and six months ended June 30, 2011, compared with the year-ago periods:

• Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes declined less than 1% and 1%, respectively, attributable to continued economic pressure, energy efficiency measures and customer conservation efforts ($26 million and $24 million, respectively).

• Unfavorable weather conditions, as evidenced by a 13% and 11% decrease compared to year-ago periods in cooling degree-days, respectively ($17 million and $22 million, respectively). Weather conditions in Ameren Missouri’s service territory were warmer than normal as

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evidenced by a 21% and 22% increase compared to normal in cooling degree-days for the quarter and year-to-date periods, respectively.

• Lower wholesale sales due to a reduction in customers and expiration of contracts and inclusion of replacement sales in the FAC ($13 million and $31 million, respectively).

• A reduction in revenues resulting from the MoPSC’s order with respect to its FAC prudence review disallowance for the period from March 1, 2009 to September 30, 2009 ($17 million and $17 million, respectively). See Note 2 – Rate and Regulatory Matters under Part 1, Item 1, for further information regarding the FAC prudence review.

Ameren Missouri’s electric margins were favorably impacted by higher electric base rates, effective June 2010 ($53 million and $102 million, respectively), offset by increased net base fuel expense ($6 million and $26 million, respectively), which was a result of higher net base fuel cost rates approved in the 2010 MoPSC rate order. Net base fuel expense is the sum of fuel - production volume and other (+$4 million and -$18 million, respectively), purchased power (+$16 million and +$40 million, respectively), and off-system revenues (+$39 million and +$60 million, respectively) offset by the FAC under-recovery (-$65 million and -$108 million, respectively).

Ameren Missouri’s natural gas margins increased by $4 million, or 31%, and $4 million, or 10%, for the three and six months ended June 30, 2011, respectively, compared with the same periods in 2010. Ameren Missouri’s natural gas margins were favorably impacted by an increase in sales volumes (26% and 1%, respectively) excluding the estimated impact of abnormal weather ($3 million and $2 million, respectively) and higher natural gas rates, effective February 2011 ($1 million and $2 million, respectively).

Ameren Illinois Regulated

Ameren Illinois 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 to alternative providers and usage.

Ameren Illinois’ electric margins increased by $17 million, or 6%, and $16 million, or 3%, for the three and six months ended June 30, 2011, respectively, compared with the same periods in 2010. The following items had a favorable impact on Ameren Illinois’ electric margins for the three and six months ended June 30, 2011, compared with the year-ago periods:

• Higher transmission revenues primarily associated with higher FERC-regulated transmission rates ($13 million and $17 million, respectively). 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 Ameren Illinois, and mild weather in 2009, which all impacted the FERC transmission rates that became effective in the second quarter of 2010.

• Increase in recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms ($12 million and $12 million, respectively). See Operations and Maintenance in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.

• Higher electric delivery service rates, effective in early May 2010 and November 2010 ($7 million and $10 million, respectively).

The following items had an unfavorable effect on Ameren Illinois’ electric margins for the three and six months ended June 30, 2011, compared with the year-ago periods:

• Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes declined 4% and 1%, respectively, attributable to continued economic pressure, energy efficiency measures and customer conservation efforts ($7 million and $10 million, respectively.)

• Decrease in recovery of prior years’ bad debt expense under the Illinois bad debt rider, which became effective March 2010 ($4 million and $6 million, respectively). See Operations and Maintenance in this section for additional information on a related offsetting decrease in bad debt expense.

• Unfavorable weather conditions, as evidenced by a 14% and 13% decrease compared to year-ago periods in cooling degree-days, respectively ($3 million and $5 million, respectively). Weather conditions in Ameren Illinois’ service territory were warmer than normal as evidenced by a 17% increase in cooling degree-days for the quarter and year-to-date periods.

Ameren Illinois’ natural gas margins decreased by $5 million, or 6%, and $11 million, or 5%, for the three and six months ended June 30, 2011, respectively, compared with the same periods in 2010. The following items had an unfavorable impact on Ameren Illinois’ natural gas margins for the three and six months ended June 30, 2011, compared with the year-ago periods:

• Decrease in recovery of prior years’ bad debt expense under the Illinois bad debt rider, which became effective March 2010 ($4 million and $5 million, respectively). See Operations and Maintenance in this section for additional information on a related offsetting decrease in bad debt expense.

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• 18% and 6% lower sales volumes, respectively, excluding the estimated impact of abnormal weather, largely in the commercial and industrial sectors attributable to continued economic pressure ($6 million and $5 million, respectively).

• Decrease in recovery of energy efficiency and environmental remediation costs through Illinois rate-adjustment mechanisms by $1 million for the year-to-date period; however, there was an increase of $2 million for the second quarter. See Operations and Maintenance in this section for information on a related offsetting decrease in energy efficiency and environmental remediation costs.

Ameren Illinois’ natural gas margins were impacted by favorable weather conditions, as evidenced by a 58% and 1% increase compared to year-ago periods in heating degree-days, respectively ($2 million and less than $1 million, respectively). Weather conditions in Ameren Illinois’ service territory were cooler than normal as evidenced by a 1% and 6% increase compared to normal in heating degree-days for the quarter and year-to-date periods, respectively.

Merchant Generation

Merchant Generation’s electric margins increased by $13 million, or 9%, for the three months ended June 30, 2011, compared with the same period in 2010; however, margins decreased by $32 million, or 9%, for the six months ended June 30, 2011, compared with the same period in 2010.

Genco

Genco’s electric margins decreased by $9 million, or 7%, and $21 million, or 8%, for the three and six months ended June 30, 2011, respectively, compared with the same periods in 2010. The following items had an unfavorable impact on Genco’s electric margins for the three and six months ended June 30, 2011, compared with the year-ago periods (except where a specific period is referenced):

• 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 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 under both power supply agreements was mitigated by a settlement of a contract dispute with a large customer in the second quarter of 2011. The net impact of the foregoing resulted in a $5 million favorable price variance for the quarter but a $4 million unfavorable price variance for the year-to-date period.

• Decreased energy center utilization, primarily due to planned and unplanned outages. Genco’s lower production volume decreased electric revenues by $18 million and $34 million, respectively, which was mitigated by lower production volume costs of $14 million and $21 million, respectively. Genco’s baseload coal-fired energy centers’ average capacity factor decreased to 65% in the second quarter of 2011, compared with 69% in the second quarter of 2010, and Genco’s equivalent availability factor decreased to 79% in the second quarter of 2011, compared with 87% in the second quarter of 2010. Genco’s average capacity factor decreased to 67% year-to-date in 2011, compared with 71% year-to-date in 2010, and Genco’s equivalent availability factor decreased to 79% year-to-date in 2011, compared with 85% year-to-date in 2010.

• 6% higher fuel prices, for both the three and six months ended June 30, 2011, primarily due to higher commodity and transportation costs associated with new supply contracts ($6 million and $16 million, respectively).

Net unrealized MTM activity on fuel-related transactions, primarily associated with financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts, and on nonqualifying power hedges was unfavorable for the second quarter, which reduced margins by $4 million; however, the net year-to-date MTM activity was favorable, which increased margins by $10 million.

Other Merchant Generation

Electric margins from Ameren’s other Merchant Generation operations, primarily AERG and Marketing Company, increased by $22 million, or 81% for the three months ended June 30, 2011, compared with the same period in 2010; however, margins decreased by $11 million, or 10% for the six months ended June 30, 2011, compared with the same period in 2010. The following items had an unfavorable impact on Ameren’s other Merchant Generation operations’ electric margins for the three and six months ended June 30, 2011, compared with the year-ago periods:

• Net unrealized MTM activity, principally at Marketing Company, largely related to nonqualifying power hedges, was favorable for the second quarter, which increased margins by $24 million; however, the year-to-date activity was unfavorable, which reduced margins by $4 million.

• Decreased energy center utilization at AERG, primarily due to planned and unplanned outages. AERG’s lower production volume decreased electric revenues by $13 million and $21 million, respectively, which was mitigated

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by lower production volume costs of $4 million and $9 million, respectively. AERG’s baseload coal-fired energy centers’ average capacity factor decreased to 65% in the second quarter of 2011, compared with 73% in the second quarter of 2010, and AERG’s equivalent availability factor decreased to 72% in the second quarter of 2011, compared with 83% in the second quarter of 2010. AERG’s average capacity factor decreased to 70% year-to-date in 2011, compared with 77% year-to-date in 2010, and AERG’s equivalent availability factor decreased to 76% year-to-date in 2011, compared with 85% year-to-date in 2010.

• 7% and 9% higher fuel prices at AERG, respectively, primarily due to higher commodity and transportation costs associated with new supply contracts ($2 million and $5 million, respectively).

Other Merchant Generation’s electric margins were favorably impacted by a settlement of a contract dispute with a large customer in the second quarter of 2011, partially offset by 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. In accordance with the AERG PSA, AERG was also allocated a lower percentage of revenues from the pool because of lower reimbursable expenses and lower levels of generation relative to Genco. The net impact of the settlement of the contract dispute and lower market prices resulted in a favorable price variance for the quarter and year-to-date periods ($8 million and $5 million, respectively).

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren Corporation

Three months - Other operations and maintenance expenses increased $10 million in the second quarter of 2011, compared with the same period in 2010.

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

• A $16 million increase in storm repair costs, due to major storms in the second quarter of 2011.

• Energy efficiency and environmental remediation costs, increased by $14 million at Ameren Illinois. These costs are recovered through customer billings and offset by increased revenues, with no overall impact on net income.

• Other operations and maintenance expenses were reduced in the prior-year period by $11 million for a May 2010 MoPSC electric rate order, which resulted in Ameren Missouri recording regulatory assets related to employee severance costs and storm costs incurred in 2009.

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

• Plant maintenance costs decreased by $26 million, primarily because of the timing of refueling and maintenance outages at the Callaway energy center. Maintenance and labor costs associated with the refueling and maintenance outage performed in the second quarter of 2010 were $35 million. The 2011 refueling and maintenance outage is scheduled to occur in the fourth quarter.

• A $7 million decrease in bad debt expense. Bad debt expense decreased primarily because of adjustments under the Ameren Illinois bad debt rider mechanism. Expense recorded under the Ameren Illinois bad debt rider mechanism is recovered through customer billings, with no overall effect on net income.

Six months - Other operations and maintenance expenses were $36 million higher in the first six months of 2011, as compared with the first six months of 2010.

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

• A $34 million increase in storm repair costs, primarily due to major storms in the second quarter of 2011.

• An $11 million increase in Ameren Illinois’ energy efficiency and environmental remediation costs, which are recovered through customer billings and offset by increased revenues, with no overall impact on net income.

• Other operations and maintenance expenses were reduced in the prior-year period by $11 million for a May 2010 MoPSC rate order, which resulted in the recording of regulatory assets related to 2009 employee severance costs and storm costs in the second quarter of 2010, as noted above.

• Labor costs increased by $9 million, primarily because of wage increases.

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

• Plant maintenance costs decreased by $32 million, primarily because of the timing of refueling and maintenance outages at the Callaway energy center between years. The 2011 refueling and maintenance outage is scheduled to occur in the fourth quarter of 2011.

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• A $9 million reduction in non-storm-related distribution maintenance expenditures due, in part, to the deployment 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 and six months ended June 30, 2011, compared with the same periods in 2010, were as follows:

Ameren Missouri

Three months - Other operations and maintenance expenses decreased $9 million, primarily as a result of the timing of refueling and maintenance outages at the Callaway energy center between years, as noted above. Offsetting this favorable item was a reduction in expenses in the prior-year period of $11 million for the 2010 MoPSC electric rate order, as noted above, and a $9 million increase in storm costs between periods.

Six months - Other operations and maintenance expenses increased $6 million. Storm repair costs increased by $20 million and labor costs were $8 million higher, primarily due to wage increases. Additionally, expenses were reduced in the prior-year period by $11 million for the 2010 MoPSC electric rate order, as noted above. Mitigating these unfavorable items was a reduction in plant maintenance costs of $34 million, primarily because of the timing of refueling and maintenance outages at the Callaway energy center between years, as noted above.

Ameren Illinois Regulated Segment

Three months - Other operations and maintenance expenses increased $22 million. Energy efficiency and environmental remediation costs increased by $14 million and storm costs were higher by $7 million. Mitigating these unfavorable items was a reduction in bad debt expense of $6 million, primarily because of adjustments under the Ameren Illinois bad debt rider mechanism, as noted above.

Six months - Other operations and maintenance expenses increased $28 million. Energy efficiency and environmental remediation costs increased by $11 million, storm costs were higher by $14 million, and labor costs increased by $4 million, primarily due to wage increases. Mitigating these unfavorable items was a reduction in non-storm-related distribution maintenance expenditures of $7 million.

Merchant Generation

Three months - Other operations and maintenance expenses increased $7 million in the Merchant Generation segment, primarily as a result of increased plant maintenance costs at AERG resulting from planned outages. Other operations and maintenance expenses were comparable between periods at Genco.

Six months - 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 because of gains from sales of properties of $6 million.

Depreciation and Amortization

Ameren Corporation

Three and six months - Ameren’s depreciation and amortization expenses increased $4 million and $12 million in the three and six months ended June 30, 2011, respectively, compared with the same periods in 2010, primarily because of items noted below at Ameren Missouri.

Variations in depreciation and amortization expenses in Ameren’s business segments and for the Ameren Companies for the three and six months ended June 30, 2011, compared with the same periods in 2010, were as follows:

Ameren Missouri

Three and six months - Depreciation and amortization expenses increased $6 million and $14 million, respectively, primarily because of capital additions and an increase in Ameren Missouri’s annual depreciation rate as a result of the 2010 MoPSC electric rate order.

Ameren Illinois Regulated Segment and Merchant Generation

Three and six months - Depreciation and amortization expenses were comparable between periods in the Ameren Illinois Regulated Segment, in the Merchant Generation Segment, and at Genco.

Taxes Other Than Income Taxes

Ameren Corporation

Three and six months - Ameren’s taxes other than income taxes increased $7 million and $11 million in the three and six months ended June 30, 2011, respectively, compared with the same periods in 2010, primarily because of items noted below at Ameren Missouri.

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Variations in taxes other than income taxes in Ameren’s business segments and for the Ameren Companies for the three and six months ended June 30, 2011, compared with the same periods in 2010, were as follows:

Ameren Missouri

Three months - Taxes other than income taxes increased $8 million, primarily because of higher property taxes, due to higher state and local assessments and increased tax rates.

Six months - Taxes other than income taxes increased $13 million, primarily because of increased property taxes as discussed above, and higher gross receipts taxes from increased sales.

Ameren Illinois Regulated Segment and Merchant Generation

Three and six months - Taxes other than income taxes were comparable between periods in the Ameren Illinois Regulated Segment, in the Merchant Generation Segment, and at Genco.

Other Income and Expenses

Ameren Corporation

Three and six months - Miscellaneous income, net of expenses, decreased $10 million and $14 million, respectively, in the three and six months ended June 30, 2011, as compared with the same periods in 2010, because of items noted below at the Ameren Companies.

Variations in miscellaneous income, net of expenses, in Ameren’s business segments and for the Ameren Companies for the three and six months ended June 30, 2011, compared with the same periods in 2010, were as follows:

Ameren Missouri

Three and six months - Miscellaneous income, net of expenses decreased $6 million and $15 million, respectively, 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 energy center, which were placed in service in late 2010.

Ameren Illinois Regulated Segment and Merchant Generation

Three and six months - Miscellaneous income, net of expenses, was comparable between periods in the Ameren Illinois Regulated Segment, in the Merchant Generation Segment, and at Genco.

Interest Charges

Ameren Corporation

Three and six months - Interest charges decreased $11 million and $24 million, respectively, in the three and six months ended June 30, 2011, as compared with the same periods in 2010, because of items noted below at the Ameren Companies and because of reduced credit facility borrowings at Ameren.

Variations in interest charges in Ameren’s business segments and for the Ameren Companies for the three and six months ended June 30, 2011, compared with the same periods in 2010, were as follows:

Ameren Missouri

Three months - Interest charges were comparable as reductions in interest charges associated with uncertain tax positions and higher allowance for borrowed funds used during construction were offset by an increase in interest charges resulting from the May 2010 MoPSC electric rate order. The rate order resulted in a reduction of interest charges of $10 million in the prior-year period, through the recording of a regulatory asset for recovery of bank credit facility fees incurred in 2009.

Six months - Interest charges decreased $3 million, primarily because of a reduction in interest charges associated with uncertain tax positions, higher allowance for borrowed funds used during construction, the redemption of $66 million of subordinated deferrable interest debentures in September 2010, and reduced amortization of credit facility fees. Offsetting these favorable items was a reduction in interest charges in the prior-year period due to the May 2010 MoPSC electric rate order, as discussed above.

Ameren Illinois Regulated Segment

Interest charges were comparable between periods.

Merchant Generation

Three and six months - Interest charges decreased $10 million and $16 million, respectively, in the Merchant Generation segment, because of items discussed below at Genco and because of reduced intercompany borrowings at AERG.

Genco

Three and six months - Interest charges decreased $6 million and $8 million, respectively, at Genco, primarily because of the maturity and repayment of $200 million of senior unsecured notes in November 2010.

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Income Taxes

The following table presents effective income tax rates for the registrants and by segment for the three and six months ended June 30, 2011, and 2010:

	Three Months						Six Months
	2011			2010			2011			2010
Ameren		37	%		35	%		37	%		38	%
Ameren Missouri		37			34			36			36
Ameren Illinois		41			39			39			40
Genco		43			46			42			44
Merchant Generation		21			(a	)		39			43

(a) Not measurable.

Ameren Corporation

Three months - Ameren’s effective tax rate in the second quarter of 2011 was higher than the second quarter of 2010, primarily due to the impact of an increase in the Illinois statutory tax rate effective at the beginning of 2011, along with lower favorable net amortization of property-related regulatory assets and liabilities in the current period compared with the same period last year and changes to reserves for uncertain tax positions.

Six months - Ameren’s effective tax rate in the first six months of 2011 was lower than the same period in 2010. There was 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 partially offset by the impact of an increase in the Illinois statutory tax rate effective at the beginning of 2011, along with lower favorable net amortization of property-related regulatory assets and liabilities in 2011 compared with 2010 and changes to reserves for uncertain tax positions.

Variations in effective tax rates in Ameren’s business segments and for the Ameren Companies for the three and six months ended June 30, 2011, compared with the same periods in 2010, were as follows:

Ameren Missouri

Three months - Ameren Missouri’s effective tax rate was higher, primarily due to lower favorable net amortization of property-related regulatory assets and liabilities, along with the absence of the tax benefit of the manufacturing deduction in the current year.

Six months - Ameren Missouri’s effective tax rate was comparable between periods. The recording of the effect of the change in tax treatment of retiree health care costs in 2010, as discussed above, was offset by lower favorable net amortization of property-related regulatory assets and liabilities and higher non-deductible expenses in 2011.

Ameren Illinois Regulated Segment

Three months - Ameren Illinois Regulated Segment’s effective tax rate was higher, primarily because of the increase in the Illinois statutory income tax rate in 2011, along with unfavorable net amortization of property-related regulatory assets and liabilities in 2011 compared with favorable amortization in 2010, partially offset by favorable changes in reserves for uncertain tax positions in the current period.

Six months - Ameren Illinois Regulated Segment’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 at the beginning of 2011 and unfavorable net amortization of property-related regulatory assets and liabilities in 2011 compared with favorable amortization in 2010.

Merchant Generation

Three months - The effective rate was lower in the Merchant Generation segment, primarily because of changes in reserves for uncertain tax positions along with the decreased impact of non-deductible expenses on higher pretax book income in 2011, offset, in part, by the increase in the Illinois statutory income tax rate in 2011.

Six months - The effective tax rate was lower in the Merchant Generation segment, primarily because 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, offset, in part, by the increase in the Illinois statutory income tax rate in 2011.

Genco

Three months - Genco’s effective tax rate was lower, primarily because of changes in reserves for uncertain tax positions, along with the favorable impact of the manufacturing deduction, partially offset by the increase in the Illinois statutory income tax rate in 2011.

Six months - Genco’s effective tax rate was lower, primarily because of changes in reserves for uncertain tax positions, and the increase in the effective tax rate from the change in the tax treatment of retiree health care costs in 2010 being higher than the increase in the Illinois statutory income tax rate in 2011.

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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 Ameren Illinois Merger. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. Ameren Illinois 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 Ameren Illinois. 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 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 support 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 Ameren Illinois 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 third-party 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 third-party external financing will not be required.

The following table presents net cash provided by (used in) operating, investing and financing activities for the six months ended June 30, 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)	$	903	$	771	$	132		$	(498	)	$	(560	)	$	62		$	(572	)	$	(327	)	$	(245	)
Ameren Missouri		353		287		66			(320	)		(351	)		31			(156	)		(112	)		(44	)
Ameren Illinois		405		332		73			(125	)		(111	)		(14	)		(349	)		(144	)		(205	)
Genco		88		147		(59	)		(11	)		(62	)		51			(76	)		(84	)		8

(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 six months of 2011 compared with the first six months of 2010. The following items contributed to the increase in cash from operating activities during the first six months of 2011, compared with the same period in 2010:

• Ameren Missouri’s regulatory asset for FAC under-recovery decreased by $203 million as more deferred costs were recovered from customers during 2011.

• A $92 million decrease in collateral posted with counterparties due primarily to the items discussed at the registrant subsidiaries below and a $29 million reduction in postings with MISO at Ameren due to changes in the market price of power.

• Deferred budget billing receivables decreased by $62 million, partially as a result of milder weather, which decreased sales volumes compared with budget-billed amounts.

• The absence in 2011 of a Callaway energy center refueling and maintenance outage, which occurred during the second quarter of 2010 and which resulted in payments of $25 million.

• A $16 million decrease in interest payments, primarily due to the long-term debt redemptions at the registrant subsidiaries discussed below and a reduction in Ameren’s borrowings under its credit facility agreements.

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• 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 Ameren Illinois.

• An $8 million increase in Illinois electric commodity over-recovered costs caused, in part, by MISO resettlements.

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

• Income tax payments of $1 million in 2011, compared with income tax refunds of $100 million in 2010. The 2010 refund resulted primarily from a 2009 change in tax treatment of electric generation plant expenditures, storm damage deductions, and accelerated deductions authorized by the economic stimulus legislation.

• A $57 million decrease in cash from operating activities associated with the December 2005 Taum Sauk incident, primarily as a result of insurance recoveries received in 2010, but not in 2011.

• Electric and natural gas margins, as discussed in Results of Operations, decreased by $32 million, excluding impacts of noncash MTM transactions.

• A $29 million increase in major storm restoration costs.

• A $12 million increase in pension plan contributions.

• A $12 million increase in property tax payments caused primarily by higher assessed tax values and rates in Missouri.

• A $12 million increase in Ameren Missouri 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, of this report for additional information.

• An $11 million decrease in natural gas commodity over-recovered costs under the PGA, primarily in Illinois.

• Weaker collection results as more utility customers were past due on their bills as of June 30, 2011, compared with June 30, 2010.

Ameren Missouri

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

• The regulatory asset for FAC under-recovery decreased by $203 million as more deferred costs were recovered from customers during 2011.

• The absence in 2011 of a Callaway energy center refueling and maintenance outage, which occurred during the second quarter of 2010 and which resulted in payments of $25 million.

• Deferred budget billing balances decreased by $20 million, partially as a result of milder weather, which decreased sales volumes compared with budget-billed amounts.

• A $3 million decrease in interest payments, primarily due to the redemption of subordinated deferrable interest debentures in September 2010.

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

• Income tax payments of $12 million in 2011, compared with income tax refunds of $81 million in 2010. The 2010 refund resulted primarily from a 2009 change in tax treatment of electric generation plant expenditures and accelerated deductions authorized by economic stimulus legislation.

• A $57 million decrease in cash from operating activities associated with the December 2005 Taum Sauk incident, primarily as a result of insurance recoveries received in 2010, but not in 2011.

• An $18 million increase in major storm restoration costs.

• A $12 million increase in receivables held in court registries under the appeals of the MoPSC’s 2009 and 2010 rate orders.

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

• Weaker collection results as more customers were past due on their bills as of June 30, 2011, compared with June 30, 2010.

• A $6 million increase in energy efficiency expenditures for new customer programs.

• Electric and natural gas margins, as discussed in Results of Operations, decreased by $3 million, excluding impacts of noncash MTM transactions.

Ameren Illinois

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

• A $63 million decrease in collateral posted with counterparties due, in part, to changes in the market price of natural gas.

• Deferred budget billing balances decreased by $42 million, partially as a result of milder weather, which decreased sales volumes compared with budget-billed amounts.

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• 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.

• An $8 million increase in electric commodity over-recovered costs caused, in part, by MISO resettlements.

• Electric and natural gas margins, as discussed in Results of Operations, increased by $5 million, excluding impacts of noncash MTM transactions.

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

• Income tax payments of $3 million in 2011, compared with income tax refunds of $33 million in 2010. The 2010 refund resulted primarily from storm damage deductions and accelerated deductions authorized by the economic stimulus legislation.

• An $11 million increase in major storm restoration costs.

• An $11 million decrease in natural gas commodity over-recovered costs under the PGA.

• Weaker collection results as more customers were past due on their bills as of June 30, 2011, compared with June 30, 2010.

Ameren Illinois’ 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, Ameren Illinois distributed AERG to Ameren and, therefore, Ameren Illinois’ operating cash flows during 2011 did not include AERG.

Genco

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

• Electric margins, as discussed in Result of Operations, decreased by $31 million, excluding impacts of noncash MTM transactions.

• A $7 million increase in income tax payments, primarily due to fewer deductions relating to environmental expenditures and a reduction in accelerated depreciation deductions authorized by the economic stimulus legislation.

• A $7 million increase in payments associated with major outages at coal-fired energy centers.

• A $6 million increase in pension plan contributions as EEI made a contribution in 2011, but did not in 2010.

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

• The prepayment of $3 million for insurance associated with a project to construct scrubbers at the Newton energy center.

• The unpaid DOE reimbursement for costs incurred while exploring the potential repowering of the Meredosia energy center redesigned for permanent CO₂ capture and storage, totaled $3 million.

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

• A $6 million decrease in interest payments, primarily due to the redemption of senior notes in November 2010.

• A $3 million reduction in use tax payments in 2011 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 six months of 2011 compared with the first six months of 2010. Net cash used for capital expenditures decreased in 2011 as a result of the completion of two energy center scrubber projects and boiler projects in 2010. The reductions in capital expenditures were offset, in part, by an increase in storm restoration costs and the startup costs of a third energy center scrubber project in 2011. Cash flows from investing activities also benefited from an increase of proceeds from sales of properties.

Ameren Missouri’s cash used in investing activities decreased during the first six months of 2011, compared with the same period in 2010, principally because of a $49 million decrease in capital expenditures primarily as a result of the completion in 2010 of two scrubbers at its Sioux energy center and boiler projects, which more than offset a $23 million increase in capital expenditures related to storm restoration costs. This cash benefit was reduced by a $11 million increase in nuclear fuel expenditures related to the timing of purchases.

Ameren Illinois’ cash used in investing activities increased during the first six months of 2011, compared with the same period in 2010, principally because of a $27 million increase in capital expenditures primarily as a result of increased investment in new transmission lines and a $15 million increase in capital expenditures related to storm restoration costs. The 2011 cash benefit of $49 million related to repayments of advances previously paid to ATXI as a result of the completion of a project under a joint ownership agreement was largely offset by the 2010 cash benefit of $45 million related to proceeds received on an intercompany note.

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Genco’s cash used in investing activities decreased during the first six months of 2011, compared with the same period in 2010. Net cash used for capital expenditures increased by $25 million primarily as a result of increased spending for energy center scrubber projects and boiler projects. The Coffeen energy center scrubber project was completed in February 2010, and construction began in April 2011 on its Newton energy center scrubber project. In 2011, cash flows from investing activities benefited from the proceeds of property sales, principally attributed to $45 million of proceeds received from the sale of Genco’s interest in its Columbia CT facility, and net receipt of non-state-regulated subsidiaries’ money pool advances. In 2010, the cash benefit of proceeds received from the sale of 25% of Genco’s Columbia CT facility was offset by net money pool advances.

Capital Expenditures

The following table provides estimates of capital expenditures that are expected to be incurred by the Ameren Companies from 2011 through 2015, including construction expenditures, capitalized interest for Ameren’s Merchant Generation business and allowance for funds used during construction for Ameren’s rate-regulated utility businesses, and estimated expenditures for compliance with environmental standards. The estimated 2011 to 2015 capital expenditures at Ameren have declined, compared to those estimates disclosed in the Form 10-K primarily due to reductions at Ameren Missouri and Genco offset by an increase at Ameren Illinois. Ameren Missouri and Genco reduced their total estimated 2011 to 2015 capital expenditures by $500 million and $250 million, respectively, compared to those estimates disclosed in the Form 10-K. Ameren Missouri’s reduction in estimated capital expenditures is primarily a result of decreased estimated expenditures for compliance with environmental standards due to its multi-year agreement, which was entered into in July 2011, to procure ultra low-sulfur coal. The reduction at Genco is primarily a result of its continued optimization of environmental compliance plans and reductions of discretionary non-environmental spending. See Note 9 - Commitments and Contingencies under Part I, Item 1, of this report for a discussion of future environmental capital expenditure estimates. Ameren Illinois has accelerated the timing of estimated transmission spending to harden and replace existing aging transmission infrastructure as well as to expand the transmission system resulting in an increase of $210 million to their total estimated 2011 to 2015 capital expenditures, compared to those estimates disclosed in the Form 10-K.

	2011			2012 - 2015					Total
Ameren Missouri	$	650		$	2,330	-	$	2,710	$	2,980	-	$	3,360
Ameren Illinois		350			1,820	-		2,120		2,170	-		2,470
Genco		180			440	-		510		620	-		690
Other(a)		(10	)		600	-		690		590	-		680
Ameren(b)	$	1,170		$	5,190	-	$	6,030	$	6,360	-	$	7,200

(a) Includes amounts for Ameren nonregistrant subsidiaries and the effects of intercompany transfers.

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

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. Additionally, we continually review the reliability of our transmission and distribution systems, expected capacity needs, and opportunities for transmission investments. The timing and amount of investment could vary due to changes in expected capacity, the condition of transmission and distribution systems, and the ability and willingness to pursue transmission investments, among other things. Any changes that we may plan to make for future generation, transmission or distribution 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 increased during the six months ended June 30, 2011, compared with the same period in 2010. In June 2011, Ameren Illinois’ 6.625% $150 million senior secured notes matured and were repaid using available cash on hand. Additionally, Ameren increased its net repayments of short-term and credit facility borrowings by $32 million and its net refunds of advances previously received from generators by $51 million due to project completion.

Ameren Missouri’s net cash used in financing activities increased during the six months ended June 30, 2011, compared with the same period in 2010, as a result of a $26 million increase in net refunds of advances previously received from generators due to project completion and a $19 million increase in common stock dividends.

Ameren Illinois’ net cash used in financing activities increased during the six months ended June 30, 2011, compared to the same period in 2010. In June 2011, Ameren Illinois repaid at maturity $150 million of its 6.625% senior secured notes using available cash on hand and operating cash flows. Additionally, in 2011, common stock dividends increased $83 million and net refunds of advances previously received from generators increased $24 million due to project completion. The cash used in financing activities in 2011 was reduced by a $6 million capital contribution from Ameren. In 2010, discontinued operations used net cash of $45 million for financing activities.

Genco’s net cash used in financing activities decreased during the six months ended June 30, 2011, compared with the same period in 2010. In 2011 and 2010, Genco utilized the surplus of net cash provided by operating activities in excess of net cash used in investing activities to repay

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borrowing obligations. In 2011, Genco repaid credit facility borrowings of $100 million, while in 2010, it made a $84 million payment on an intercompany note payable to Ameren. In 2011, the net repayment of credit facility borrowings was offset by a $24 million capital contribution from Genco’s parent, Resources Company.

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 regarding credit facilities, short-term borrowing activity, relevant interest rates, borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements, and commercial paper issuances.

The following table presents the committed bank credit facilities of Ameren and the Ameren Companies, and the credit capacity available under such facilities, considering reductions for commercial paper borrowings and letters of credit, as of June 30, 2011:

	Expiration	Amount Committed			Credit Available
Ameren and Ameren Missouri:
2010 Missouri Credit Agreement(a)	September 2013	$	800		$	600
Ameren and Genco:
2010 Genco Credit Agreement(a)	September 2013		500			500
Ameren and Ameren Illinois:
2010 Illinois Credit Agreement(a)	September 2013		800			800
Ameren:
$20 million revolving credit facility	June 2012		20			-
Less:
Commercial paper outstanding			(b	)		(317	)
Letters of credit			(b	)		(15	)
Total		$	2,120		$	1,568

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

(b) Not applicable.

In February 2011, AIC received approval from the ICC to extend the expiration of its borrowing sublimit under the 2010 Illinois Credit Agreement to September 10, 2013. In June 2011, Ameren Missouri received approval from the MoPSC to extend the expiration of its borrowing sublimit under the 2010 Missouri Credit Agreement to September 10, 2013.

The 2010 Credit Agreements are used for cash borrowings, to issue letters of credit, and to support borrowings under Ameren’s and Ameren Missouri’s $500 million commercial paper programs. Any of the 2010 Credit Agreements are available to Ameren to support its commercial paper programs, subject to borrowing sublimits. At June 30, 2011, Ameren had $317 million of commercial paper outstanding and $15 million of letters of credit outstanding. Based on outstanding borrowings and letters of credit issued under the 2010 Credit Agreements as of June 30, 2011, as well as commercial paper outstanding as of such date, the aggregate amount of credit capacity available under the 2010 Credit Agreements at June 30, 2011, was $1.6 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 Ameren Illinois 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.

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Long-term Debt and Equity

The following table presents the issuances of common stock and the maturities of long-term debt for the six months ended June 30, 2011 and 2010, for the Ameren Companies. For additional information, see Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report.

	Month Issued or Matured	Six Months
		2011		2010
Issuances
Common stock
Ameren:
DRPlus and 401(k)	Various	$	32	$	43
Total common stock issuances		$	32	$	43
Redemptions, Repurchases and Maturities
Long-term debt
Ameren Illinois:
6.625% Senior secured notes due 2011	June	$	150	$	-
Total Ameren long-term debt maturities		$	150	$	-

A Form S-3 registration statement was filed by Ameren with the SEC in June 2011, 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 $15 million and 1.2 million new shares of common stock valued at $32 million in the three and six months ended June 30, 2011, respectively.

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 under Part II, Item 8, of 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 June 30, 2011, the Ameren Companies were in compliance with the provisions and covenants contained within their credit facilities, indentures, and articles of incorporation.

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 $186 million, or 77 cents per share, during the first six months of 2011 (2010 - $183 million or 77 cents per share).

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 under Part II, Item 8, of 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 June 30, 2011, none of these circumstances existed at the Ameren Companies and, as a result, the Ameren Companies were allowed to pay dividends.

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The following table presents common stock dividends paid by Ameren Corporation to its common stockholders and by Ameren’s subsidiaries to their respective parents for the six months ended June 30, 2011, and 2010:

	Six Months
	2011		2010
Ameren Missouri	$	135	$	116
Ameren Illinois		150		67
Ameren		186		183

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 June 30, 2011, total other obligations related to the procurement of coal, natural gas, nuclear fuel, purchased power, methane gas, and other agreements, at Ameren, Ameren Missouri, Ameren Illinois and Genco were $10,378 million, $6,179 million, $2,782 million, and $993 million, respectively. The above stated amounts include multi-year agreements to procure ultra low-sulfur coal and the related transportation from the Powder River Basin from Wyoming that Ameren Missouri entered into in July 2011. See Note 9-Commitments and Contingencies under Part I, Item 1 of this report for additional information. Total unrecognized tax benefits at June 30, 2011, which were not included in the totals above, for Ameren, Ameren Missouri, Ameren Illinois and Genco were $198 million, $146 million, $33 million, and $16 million, respectively.

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
Ameren Missouri:
Issuer/corporate credit rating	Baa2	BBB-	BBB+
Secured debt	A3	BBB+	A
Ameren Illinois:
Issuer/corporate credit rating	Baa3	BBB-	BBB-
Secured debt	Baa1	BBB/BBB+(a)	BBB+
Senior unsecured debt	Baa3	BBB-	BBB
Genco:
Issuer/corporate credit rating	-	BBB-	BB+
Senior unsecured debt	Ba1	BBB-	BB+

(a) The BBB+ rating applies to issuances of securities secured by the mortgage associated with the former property of CILCO. The BBB rating applies to issuances of securities secured by the mortgage associated with the former property of IP and CIPS.

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 June 30, 2011, were $146 million, $17 million, $97 million, and $5 million at Ameren, Ameren Missouri, Ameren Illinois, and Genco, respectively. Cash collateral external counterparties posted with Ameren and Ameren Illinois was $2 million and $2 million, respectively, at June 30, 2011. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at June 30, 2011, could have resulted in Ameren, Ameren Missouri, Ameren Illinois or Genco being required to post additional collateral or other assurances for certain trade obligations amounting to $255 million, $67 million, $103 million, and $26 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 June 30, 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, Ameren Illinois or Genco could be required to post additional collateral or other assurances for certain trade obligations up to approximately $144 million, $- million, $- million, and $17 million, respectively. If market prices were 15% lower than June 30, 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, Ameren Illinois or Genco could be required to post additional collateral or other assurances for certain trade obligations up to approximately $129 million, $4 million, $44 million, and $46 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.

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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

• Economic recovery within the service territory of the Ameren Companies continues to be slow, negatively impacting electrical loads, exclusive of weather impacts. Residential housing and commercial electric customer counts are showing only modest increases while energy efficiency measures and customer conservation are limiting usage. Industrial electric sales in Illinois are improving due to customer expansions, while Missouri sales lag. In addition to impacting rate-regulated electric sales, these economic factors, along with low natural gas prices, are also negatively impacting power prices for Ameren’s Merchant Generation segment. 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 addition, weak economic growth can increase regulatory lag at Ameren Missouri and Ameren Illinois making it more difficult to earn equity returns allowed by regulators. Economic conditions could affect the Ameren Companies’ results of operations, financial position and liquidity. See Item 1A. - Risk Factors under Part I of the Form 10-K for additional information.

• In 2011, Ameren’s expected return on plan assets for its pension plan assets and postretirement plan assets is 8% and 7.75%, respectively. Through June 30, 2011, the actual return on investment of the pension plan assets and postretirement plan assets exceeded the expected return on an annualized basis. As a result of sovereign debt issues in Europe, national debt limit negotiations in the United States and a continued slow global economic recovery, debt and equity markets are uncertain. 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. In August 2011, Ameren Illinois expects to contribute to Ameren’s postretirement benefit plan trusts an incremental $100 million in excess of Ameren Illinois’ annual postretirement net periodic cost for regulatory purposes. This cash contribution will reduce future postretirement expense to the extent expected returns are achieved on the contribution. 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. Ameren and certain of its subsidiaries have multiyear credit facility agreements. These facilities cumulatively provide $2.1 billion of credit through September 10, 2013. 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 currently expects to invest up to $2.4 billion to retrofit its coal-fired energy centers with pollution control equipment in compliance with environmental laws and regulations. This estimated capital investment could change significantly depending upon further analysis of recently proposed and recently finalized regulations, additional federal or state requirements, new technology, variations in costs of material or labor, or alternative compliance strategies, among other factors. Any pollution control investments will result in decreased energy center availability during construction and significantly higher ongoing operating expenses. Any pollution control investments at Ameren Missouri are expected to be recoverable from ratepayers, subject to prudence 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 segment 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 energy centers to comply with environmental legislation or regulations would significantly increase future capital expenditures and operations and maintenance expenses, which if excessive could also result in the closure of coal-fired energy centers, impairment of assets, or otherwise materially adversely affect Ameren’s results of operations, financial position, and liquidity. In July 2011, the EPA issued the CSAPR. For Missouri and Illinois, emission reductions under CSAPR are required in two phases beginning in 2012, with further reductions in 2014. 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 proposed rules are scheduled to be finalized

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in November 2011. Compliance with the MACT standard is expected to be required no later than 2016 and potentially as early as late 2014. The CSAPR and the proposed MACT standard are voluminous and complex and our review is ongoing. Increased regulation of the coal-fired electric generation industry, and the corresponding higher investment and operating expense requirements, is expected to result in closure of less economic plants in the United States, which in turn may ultimately result in higher power prices. Genco’s Hutsonville and Meredosia energy centers, and a unit, specifically unit one, at AERG’s E.D. Edwards energy center, are the Merchant Generation segment’s least economic coal-fired facilities and most exposed to compliance options being prohibitively expensive. Genco’s net investment in its Hutsonville and Meredosia energy centers totaled $26 million and $1 million, respectively, and AERG’s net investment in unit one at the E.D. Edwards energy center totaled $18 million as of June 30, 2011. See Note 9 - Commitments and Contingencies under Part I, Item 1, of this report for further discussion of environmental matters.

• 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 energy center, Ameren Missouri continues to study future generation alternatives, including energy efficiency programs that could help defer new energy center construction. To prepare for the long-term need for baseload capacity, and to prepare for potentially more stringent environmental regulation of coal-fired energy centers, 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 energy center 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 energy center site. Attempts to pass legislation to maintain an option for nuclear power in the state of Missouri by recovering the costs of the ESP, subject to appropriate consumer protections, were not successful during the 2011 spring legislative session. However, support for nuclear power exists in the state of Missouri, which could lead to the passage of an ESP recovery mechanism in future legislative sessions. Ameren Missouri’s pursuit of an ESP is dependent upon enactment of a legislative framework ensuring cost recovery. As of June 30, 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 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 energy center’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.

• 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. FERC, in its order issued in May 2011, approved transmission rate incentives for ATX, Ameren Missouri and Ameren Illinois. Ameren expects to proceed with engineering and construction of these projects pending MISO approval. Ameren expects to receive MISO approval of several projects by the end of 2011.

• In September 2010, Resources Company announced that it signed a cooperative agreement with the DOE that could lead to repowering Genco’s Meredosia energy center. This would create the world’s first full-scale, oxy-combustion coal-fired plant designed for permanent CO₂capture 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 would initiate the construction necessary to repower the energy center. Phase one of this project is scheduled to be completed by September 30, 2011.

• 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 Ameren Illinois 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 Ameren Illinois anticipate regulatory lag until their requests to increase rates to recover such costs on a timely basis are granted by state regulators. Ameren Missouri and Ameren Illinois expect to file rate cases frequently and to align operations and maintenance spending and capital investments with the revenue and related cash flow levels provided by regulators in order to mitigate regulatory lag. In future rate cases and through the legislative process, Ameren

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Missouri and Ameren Illinois will also 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 Ameren Illinois’ 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.

• Ameren Illinois filed a request with the ICC in February 2011, which was revised in July 2011, to increase its annual revenues for electric delivery service by $40 million and for natural gas delivery service by $50 million. In June 2011, the ICC staff responded to Ameren Illinois’ original filed requests. The ICC staff recommended a net decrease in revenues for electric delivery service of $10 million and a net increase in revenues for natural gas delivery service of $16 million. Ameren Illinois used 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.

• Ameren Illinois 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. Eight of nine affected wholesale customers filed protests with FERC objecting to the proposed rates. In March 2011, FERC issued an order authorizing the proposed rates to take effect, subject to refund when the final rates are determined. We cannot predict the ultimate outcome of these filings or their impact on Ameren’s or Ameren Illinois’ 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 as it applies specifically to Noranda’s electric service account. Noranda was also directed to deposit the contested amounts into the court’s registry and, as of June 30, 2011, had deposited $16 million in this account. The merits of this case are currently being tried before the Missouri Court of Appeals, Southern District with a decision expected in 2011. Separately, 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. As of June 30, 2011, the four industrial customers have made payments, excluding the bond amount, totaling $8 million, into the court’s registry. The merits of this case are currently being tried before the Cole County Circuit Court with a decision expected in 2011. If Ameren Missouri were to conclude that some portion of the rate increases authorized by the 2009 and 2010 MoPSC electric rate orders 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. The MIEC and MoOPC also attempted to expand the stay granted to them by the Cole County Circuit Court to all Ameren Missouri customers, but this position was not accepted by either the MoPSC or the Cole County Circuit Court.

• On July 13, 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of approximately $173 million, including $52 million related to an 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. The rate changes became effective on July 31, 2011. In addition to increasing annual revenues, the MoPSC order shortened the FAC recovery and refund period from 12 months to 8 months. The MoPSC order also contained a tracking mechanism for uncertain income tax positions. The MoPSC disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance. As a result of the order, Ameren and Ameren Missouri will each record a pretax charge to earnings of $89 million, relating to the Taum Sauk disallowance, in the third quarter ending September 30, 2011. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for additional information. Depreciation for the Sioux scrubbers, previously deferred as a regulatory asset when placed in service in November 2010, will result in an increase in annual expense of $21 million, beginning in August 2011. In addition, capitalization of interest was discontinued on July 31, 2011. In July 2011, Ameren Missouri and other parties to the rate case filed for rehearing of various aspects of the order including the disallowance of Taum Sauk enhancements. The MoPSC rejected the request. Subsequently, Ameren Missouri appealed the disallowance of Taum Sauk enhancements to the Missouri Court of Appeals, Western District. Ameren Missouri cannot predict the ultimate outcome of its appeal.

• In January 2011, the MoPSC approved a stipulation and agreement that resolved a June 2010 request by Ameren Missouri to increase annual natural gas

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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.

• In April 2011, the MoPSC issued an order with respect to its prudence 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. As a result of the order, Ameren Missouri recorded a pretax charge to earnings of $18 million, including $1 million for interest, 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. In June 2011, Ameren Missouri filed an appeal to the Cole County Circuit Court. A decision is expected by the Cole County Circuit Court in 2011. Separately, in July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order, that would allow Ameren Missouri to defer, as a regulatory asset, fixed costs totaling $36 million that were not recovered from Noranda as a result of the loss of load caused by the severe 2009 ice storm, for potential recovery in a future electric rate case. We cannot predict the ultimate outcome of these regulatory or judicial proceedings. 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. 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.

• 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. Nearly all of Merchant Generation’s 2011 margin is expected to be generated from sales of output from five baseload energy centers (Newton, Joppa, Coffeen, E.D. Edwards and Duck Creek). The Merchant Generation segment expects to have available generation from its coal-fired energy centers 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 29.5 million megawatthours of power from its coal-fired energy centers 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 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 June 30, 2011, Marketing Company had hedged approximately 27.5 million megawatthours of Merchant Generation’s expected generation for the remainder of 2011, at an average price of $45 per megawatthour. For 2012, Marketing Company had hedged approximately 19.5 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $47 per megawatthour. For 2013, Marketing Company had hedged approximately 10 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $41 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 $44 million, $16 million, and $4 million, respectively. Any unhedged forecasted generation will be exposed to market prices at the time of sale. Prices for power have decreased significantly since mid-2008. As a result, any new physical or financial power sales may be at price levels lower than previously experienced and lower than the value of existing hedged sales.

• The development of a capacity market in MISO could increase the electric margins of Ameren’s Merchant Generation segment and Genco. A capacity requirement obligates a load serving entity to acquire capacity sufficient to meet its obligations. In July 2011, MISO filed with FERC its proposal to establish a capacity market within the RTO. MISO asked FERC to rule on its proposal by the end of February 2012. MISO announced its intention is to hold the first annual capacity auction in April 2013 for the June 2013 to May 2014 planning year. The Ameren Companies are studying the MISO proposal and its potential impact on their results of operations, financial position, and liquidity.

• Current and future energy efficiency programs developed by Ameren Missouri, Ameren Illinois and

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others have and could continue to 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.

• Cooling degree-days in Ameren’s service territories during July 2011 were 45% higher than normal July weather conditions and 18% higher than July 2010. This hotter weather will have a favorable impact on Ameren Missouri’s and Ameren Illinois’ results of operations.

Fuel and Purchased Power

• In 2010, 85% of Ameren’s electric generation (Ameren Missouri - 77%, Genco - 99%) was supplied by coal-fired energy centers. About 97% of the coal used by these energy centers (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. Currently, flooding in the Midwest has reduced coal deliveries below normal levels at certain energy centers. As of June 30, 2011, overall coal inventories for Ameren, Ameren Missouri and Genco were at targeted levels. 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 June 30, 2011, Merchant Generation had hedged approximately 29 million megawatthours at about $23 per megawatthour. For 2012, Merchant Generation had hedged approximately 18 million megawatthours at about $23.50 per megawatthour. For 2013, Merchant Generation had hedged approximately 7 million megawatthours at about $26.50 per megawatthour. 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 energy center. This resulted in significant flooding in the local area, which damaged a state park. The rebuilt Taum Sauk energy center became fully operational in April 2010. Until Ameren’s remaining liability insurance claims and the related litigation are resolved, 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. As a result of the July 2011 MoPSC electric rate order discussed above, Ameren and Ameren Missouri will record, in the third quarter ended September 30, 2011, a pretax charge to earnings of $89 million to reflect the disallowance of certain Taum Sauk rebuild costs. 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 energy center’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 owner of the Callaway energy center, Ameren and Ameren Missouri are closely monitoring the nuclear-related developments in Japan resulting from the March 2011 earthquake and tsunami and the related NRC review of the United States nuclear power industry launched following those events. In July 2011, the NRC issued a report, which concluded that United States nuclear power plants are operating safely and recommended actions to enhance nuclear plant readiness to safely manage severe events. The NRC report made recommendations in other areas, which Ameren and Ameren Missouri are currently reviewing. Implementation of the full scope of recommendations in the report, if approved by the NRC commissioners, could reshape the agency’s regulatory framework. 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 these developments on Ameren’s or Ameren Missouri’s results of operations, financial position, and liquidity.

• 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 (Ameren Illinois - $3 million to $6 million, Genco - $1 million to $2 million).

• Ameren Missouri, Ameren Illinois, ATXI and Marketing Company are MISO members. Each member company of MISO is responsible for a portion of MISO’s market cost. FirstEnergy Corp. departed MISO on June 1, 2011, while Duke Energy Corporation (Ohio and Kentucky) will

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depart MISO 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. 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

• In May 2011, legislation was passed in both the Illinois House of Representatives and Senate that would change the ratemaking process and would modernize the electric distribution system. The legislation has not been sent to the Governor for his approval. The legislation would apply electric utilities in Illinois on an opt-in basis. The legislation includes a formula-based 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 a process FERC uses for ratemaking. If the legislation were to be enacted in its current form, Ameren Illinois would anticipate opting-in to participate in this process and would anticipate adopting the formula rate and investing an additional $625 million in capital expenditures over the next ten years to modernize its distribution system. These investments would be incremental to Ameren Illinois’ 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 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. Contracts with multiple unions expired on June 30, 2011; however, those agreements are being extended while negotiations continue. 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 and Genco’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 estimates that these provisions will result in a reduction of Ameren’s 2011 federal income tax payments of between $175 million to $225 million (Ameren Missouri - $90 million to $110 million, Ameren Illinois - $80 million to $90 million, Genco - $5 million to $15 million) and a reduction of Ameren’s 2012 federal income tax payments of between $150 million to $200 million (Ameren Missouri - $90 million to $110 million, Ameren Illinois - $50 million to $70 million, Genco - $- million to $10 million).

• 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 proposed rulemakings to implement the new law. In June 2011, the Commodity Futures Trading Commission voted to extend the rulemaking process until December 31, 2011. 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 final rulemakings, 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

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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 June 30, 2011 were to increase by 1%:

	Interest Expense			Net Income(a)
Ameren(b)	$	8		$	(5	)
Ameren Missouri		2			(1	)
Ameren Illinois		(c	)		(c	)
Genco		-			-

(a) Calculations are based on an effective tax rate of 40%, 38%, 41% and 41% for Ameren, Ameren Missouri, Ameren Illinois 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 June 30, 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 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 June 30, 2011, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. The risk associated with Ameren Illinois’ electric and natural gas trade receivables is also mitigated by a rate adjustment mechanism that allows Ameren Illinois 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 Ameren Illinois continue to monitor the impact of increasing rates on customer collections. Ameren Missouri and Ameren Illinois 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, Ameren Illinois and Genco may have credit exposure associated with off-system or wholesale purchase and sale activity with nonaffiliated companies. At June 30, 2011, Ameren’s, Ameren Missouri’s, Ameren Illinois’ and Genco’s combined credit exposure to nonaffiliated trading counterparties, deemed below investment grade either through external or internal credit

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evaluations, was $1 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. We estimate our credit exposure to MISO associated with the MISO Energy and Operating Reserves Market to be $39 million at June 30, 2011 (2010 - $47 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 remainder of 2011 through 2015:

	Net Income(a)
Ameren(b)	$	(20	)
Ameren Missouri		(c	)
Genco		(15	)

(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.

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 coal 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. Ameren Missouri has entered into a long-term contract for ultra low-sulfur coal supply through 2017 to comply with the CSAPR. Genco purchases coal based on expected power sales,

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generally through bid procedures. Therefore, Genco’s forward coal requirements are dependent on the volume of power sales that have been contracted.

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 $11 million annually (Ameren Missouri - $8 million, Genco - $2 million). As of June 30, 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 energy center 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 energy center, 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.

The electric generating operations for Ameren, Ameren Missouri and Genco 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, Ameren Illinois 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 and MISO market. The FTRs are intended to mitigate electric transmission congestion charges related to the physical constraints of the transmission system. Depending on the congestion 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 Ameren Illinois’ 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 Ameren Illinois to pass on to retail customers prudently incurred fuel, purchased power and gas supply costs. Ameren Missouri’s and Ameren Illinois’ 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 June 30, 2011, the percentages of the projected required supply of coal and coal transportation for our coal-fired energy centers, nuclear fuel for Ameren Missouri’s Callaway energy center, natural gas for our CTs and retail distribution, as appropriate, and purchased power needs of Ameren Illinois, which does not own generation, that are price-hedged

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over the 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(b)		99	%		92	%		53	%
Coal transportation(b)		100			100			61
Nuclear fuel		100			100			82
Natural gas for generation		42			6			-
Natural gas for distribution(c)		63			33			13
Purchased power for AIC(d)		100			85			23
Ameren Missouri:
Coal(b)		97	%		100	%		87	%
Coal transportation(b)		100			100			97
Nuclear fuel		100			100			82
Natural gas for generation		36			3			-
Natural gas for distribution(c)		56			24			12
Ameren Illinois:
Natural gas for distribution(c)		64	%		34	%		13	%
Purchased power(d)		100			85			23
Genco:
Coal		100	%		80	%		11	%
Coal transportation		100			100			8
Natural gas for generation		50			-			-

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

(b) In July 2011, Ameren Missouri entered into multi-year agreements to procure ultra low-sulfur coal, and the related transportation, from the Powder River Basin. The percentages above include the low-sulfur coal agreement and related transportation agreement.

(c) 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.

(d) 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)	$	9		$	(5	)	$	11		$	(7	)
AMO(c)		(d	)		(d	)		(d	)		(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.

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, power, and uranium. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three and six months ended June 30, 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

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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 June 30, 2011	Ameren(a)			Ameren Missouri			Ameren Illinois			Genco			Other(b)
Fair value of contracts at beginning of period, net	$	(7	)	$	40		$	(438	)	$	30		$	361
Contracts realized or otherwise settled during the period		7			(2	)		74			(3	)		(62	)
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-
Fair value of new contracts entered into during the period		34			25			(3	)		-			12
Other changes in fair value		19			(18	)		52			(6	)		(9	)
Fair value of contracts outstanding at end of period, net	$	53		$	45		$	(315	)	$	21		$	302
Six Months Ended June 30, 2011
Fair value of contracts at beginning of period, net	$	(79	)	$	11		$	(493	)	$	19		$	384
Contracts realized or otherwise settled during the period		25			(6	)		144			(6	)		(107	)
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-
Fair value of new contracts entered into during the period		31			25			-			-			6
Other changes in fair value		76			15			34			8			19
Fair value of contracts outstanding at end of period, net	$	53		$	45		$	(315	)	$	21		$	302

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

(b) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

The following table presents maturities of derivative contracts as of June 30, 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	)	$	(5	)	$	(1	)	$	-	$	(15	)
Level 2(a)		2			-			-			-		2
Level 3(b)		31			(38	)		(10	)		83		66
Total	$	24		$	(43	)	$	(11	)	$	83	$	53
Ameren Missouri:
Level 1	$	(4	)	$	(4	)	$	(1	)	$	-	$	(9	)
Level 2(a)		1			-			-			-		1
Level 3(b)		46			8			(1	)		-		53
Total	$	43		$	4		$	(2	)	$	-	$	45
Ameren Illinois:
Level 1	$	(4	)	$	(1	)	$	-		$	-	$	(5	)
Level 2(a)		-			-			-			-		-
Level 3(b)		(231	)		(153	)		(9	)		83		(310	)
Total	$	(235	)	$	(154	)	$	(9	)	$	83	$	(315	)
Genco:
Level 1	$	(1	)	$	-		$	-		$	-	$	(1	)
Level 2(a)		-			-			-			-		-
Level 3(b)		15			7			-			-		22
Total	$	14		$	7		$	-		$	-	$	21

(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.

ITEM 4. CONTROLS AND PROCEDURES.

(a) Evaluation of Disclosure Controls and Procedures

As of June 30, 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

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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 Energy Center 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’s January 2009, May 2010, and July 2011 electric rate orders;

• appeal of the MoPSC’s FAC prudence review order;

• appeal of the MoPSC’s 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 Ameren Illinois 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 energy center;

• litigation alleging that CO₂ emissions from several industrial companies, including Ameren Missouri and Genco, created the atmospheric conditions that intensified Hurricane Katrina; and

• asbestos-related litigation associated with Ameren, Ameren Missouri, Ameren Illinois and Genco.

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.

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
April 1 - April 30, 2011		523	$	28.23	-	-
May 1 - May 31, 2011		1,700		29.39	-	-
June 1 - June 30, 2011		-		-	-	-
Total		2,223	$	29.12	-	-

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(a) Included in April were 523 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 obligation to distribute shares of common stock for vested performance units held by employees whose employment terminated. Included in May were 1,700 shares of Ameren common stock purchased by Ameren in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan as distribution of deferred compensation to a director upon retirement under the Ameren Corporation Deferred Compensation Plan for Members of the Board of Directors. Ameren does not have any publicly announced equity securities repurchase plans or programs.

The following table presents Ameren Illinois’ 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
April 1 - April 30, 2011		8,253	$	82.15	-	-
May 1 - May 31, 2011		-		-	-	-
June 1 - June 30, 2011		-		-	-	-
Total		8,253	$	82.15	-	-

(a) The shares of CIPS preferred stock were purchased by Ameren Illinois 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 April 1, 2011, to June 30, 2011.

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
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

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12.3	Ameren Illinois	Ameren Illinois’ 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	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois
31.6	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois
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
32.2	Ameren Missouri	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri
32.3	Ameren Illinois	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Illinois
32.4	Genco	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco
XBRL - Related Documents
101.INS**	Ameren Ameren Missouri Ameren Illinois Genco	XBRL Instance Document
101.SCH**	Ameren Ameren Missouri Ameren Illinois Genco	XBRL Taxonomy Extension Schema Document
101.CAL**	Ameren Ameren Missouri Ameren Illinois Genco	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**	Ameren Ameren Missouri Ameren Illinois Genco	XBRL Taxonomy Extension Label Linkbase Document

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101.PRE**	Ameren Ameren Missouri Ameren Illinois Genco	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF**	Ameren Ameren Missouri Ameren Illinois Genco	XBRL Taxonomy Extension Definition Document

* Compensatory plan or arrangement.

** Attached as Exhibit 101 to this report is the following financial information from each of the Ameren Companies’ Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statement of Income for the three and six months ended June 30, 2011 and 2010, (ii) the Consolidated Balance Sheet at June 30, 2011, and December 31, 2010, (iii) the Consolidated Statement of Cash Flows for the six months ended June 30, 2011 and 2010, and (iv) the Combined Notes to the Financial Statements for the six months ended June 30, 2011. For Ameren Missouri, Ameren Illinois and Genco, 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: August 9, 2011

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