AMEREN CORP (Form: 10-Q, Received: 11/08/2011 15:42:34)

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 September 30, 2011

¨	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

Union Electric Company

Yes

Ameren Illinois Company

Yes

Ameren Energy Generating Company

Yes

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

Union Electric Company

Yes

Ameren Illinois Company

Yes

Ameren Energy Generating Company

Yes

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

Union Electric Company

Yes

Ameren Illinois Company

Yes

Ameren Energy Generating Company

Yes

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


Ameren Corporation		Common stock, $0.01 par value per share - 242,239,840

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		60
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		91
Item 4.	Controls and Procedures		95

PART II	Other Information

Item 1.	Legal Proceedings		96
Item 1A.	Risk Factors		96
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		96
Item 6.	Exhibits		97

Signatures			99

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.

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 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.

NO ₂ - Nitrogen dioxide.

NWPA - Nuclear Waste Policy Act of 1982, as amended.

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 change regulatory recovery mechanisms, such as the recent passage of legislation providing for formula ratemaking in Illinois;

•

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

•

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

•

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

•

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

•

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

•

increasing capital expenditure and operating expense requirements and our ability to recover these costs through our regulatory frameworks;

•

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

•

the cost and availability of fuel such as coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power and natural gas for distribution; and the level and volatility of future market prices for such commodities, including the ability to recover the costs for such commodities;

•

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

•

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

•

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

•

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

•

our assessment of our liquidity;

•

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

•

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

•

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 new or 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.

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS.

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF INCOME (LOSS)

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Operating Revenues:
Electric	$	2,138	$	2,133	$	5,222	$	5,140
Gas		130		134		731		792

Total operating revenues		2,268		2,267		5,953		5,932


Operating Expenses:
Fuel		467		394		1,217		973
Purchased power		332		376		796		915
Gas purchased for resale		46		51		413		467
Other operations and maintenance		432		455		1,368		1,357
Goodwill, impairment and other charges		124		589		126		589
Depreciation and amortization		196		194		585		571
Taxes other than income taxes		121		119		355		342

Total operating expenses		1,718		2,178		4,860		5,214

Operating Income		550		89		1,093		718

Other Income and Expenses:
Miscellaneous income		18		24		51		70
Miscellaneous expense		5		10		15		19

Total other income		13		14		36		51
Interest Charges		113		130		336		377

Income (Loss) Before Income Taxes		450		(27)		793		392

Income Taxes		163		137		293		295


Net Income (Loss)		287		(164)		500		97
Less: Net Income Attributable to Noncontrolling Interests		2		3		6		10

Net Income (Loss) Attributable to Ameren Corporation	$	285	$	(167)	$	494	$	87


Earnings (Loss) per Common Share – Basic and Diluted	$	1.18	$	(0.70)	$	2.05	$	0.37

Dividends per Common Share	$	0.385	$	0.385	$	1.155	$	1.155
Average Common Shares Outstanding		241.7		239.3		241.2		238.4

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

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

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


	September 30, 2011		December 31, 2010
ASSETS

Current Assets:
Cash and cash equivalents	$	522	$	545
Accounts receivable – trade (less allowance for doubtful accounts of $21 and $23, respectively)		575		517
Unbilled revenue		292		406
Miscellaneous accounts and notes receivable		147		214
Materials and supplies		734		707
Mark-to-market derivative assets		94		129
Current regulatory assets		184		267
Other current assets		132		109

Total current assets		2,680		2,894

Property and Plant, Net		17,873		17,853
Investments and Other Assets:
Nuclear decommissioning trust fund		330		337
Goodwill		411		411
Intangible assets		6		7
Regulatory assets		1,213		1,263
Other assets		843		750

Total investments and other assets		2,803		2,768

TOTAL ASSETS	$	23,356	$	23,515

LIABILITIES AND EQUITY

Current Liabilities:
Current maturities of long-term debt	$	178	$	155
Short-term debt		350		269
Accounts and wages payable		410		651
Taxes accrued		161		63
Interest accrued		159		107
Customer deposits		98		100
Mark-to-market derivative liabilities		118		161
Current regulatory liabilities		123		99
Other current liabilities		251		283

Total current liabilities		1,848		1,888

Credit Facility Borrowings		-		460
Long-term Debt, Net		6,682		6,853
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		3,299		2,886
Accumulated deferred investment tax credits		81		90
Regulatory liabilities		1,464		1,319
Asset retirement obligations		439		475
Pension and other postretirement benefits		922		1,045
Other deferred credits and liabilities		469		615

Total deferred credits and other liabilities		6,674		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 242.2 and 240.4, respectively		2		2
Other paid-in capital, principally premium on common stock		5,580		5,520
Retained earnings		2,440		2,225
Accumulated other comprehensive loss		(25)		(17)

Total Ameren Corporation stockholders’ equity		7,997		7,730
Noncontrolling Interests		155		154

Total equity		8,152		7,884

TOTAL LIABILITIES AND EQUITY	$	23,356	$	23,515

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

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Nine Months Ended September 30,
	2011		2010
Cash Flows From Operating Activities:
Net income	$	500	$	97
Adjustments to reconcile net income to net cash provided by operating activities:
Goodwill, impairment and other charges		126		589
Gain on sales of properties		(12)		(5)
Net mark-to-market (gain) loss on derivatives		15		(27)
Depreciation and amortization		587		588
Amortization of nuclear fuel		51		36
Amortization of debt issuance costs and premium/discounts		17		19
Deferred income taxes and investment tax credits, net		380		409
Allowance for equity funds used during construction		(25)		(40)
Other		8		13
Changes in assets and liabilities:
Receivables		52		(154)
Materials and supplies		(34)		39
Accounts and wages payable		(191)		(170)
Taxes accrued		94		99
Assets, other		64		(107)
Liabilities, other		(4)		89
Pension and other postretirement benefits		(98)		(12)
Counterparty collateral, net		37		(24)
Taum Sauk insurance recoveries, net of costs		(1)		57

Net cash provided by operating activities		1,566		1,496

Cash Flows From Investing Activities:
Capital expenditures		(758)		(757)
Nuclear fuel expenditures		(45)		(24)
Purchases of securities – nuclear decommissioning trust fund		(163)		(207)
Sales of securities – nuclear decommissioning trust fund		147		195
Proceeds from sales of properties		50		20
Other		12		(3)

Net cash used in investing activities		(757)		(776)

Cash Flows From Financing Activities:
Dividends on common stock		(279)		(276)
Capital issuance costs		-		(15)
Dividends paid to noncontrolling interest holders		(5)		(7)
Short-term debt and credit facility repayments, net		(379)		(325)
Redemptions, repurchases, and maturities:
Long-term debt		(150)		(106)
Preferred stock		-		(52)
Issuances of common stock		49		60
Generator advances for construction refunded, net of receipts		(73)		(18)
Other		5		5


Net cash used in financing activities		(832)		(734)

Net change in cash and cash equivalents		(23)		(14)
Cash and cash equivalents at beginning of year		545		622

Cash and cash equivalents at end of period	$	522	$	608

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

UNION ELECTRIC COMPANY

STATEMENT OF INCOME

(Unaudited) (In millions)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Operating Revenues:
Electric	$	1,099	$	1,040	$	2,592	$	2,384
Gas		16		20		113		118
Other		-		-		4		1

Total operating revenues		1,115		1,060		2,709		2,503


Operating Expenses:
Fuel		249		205		682		441
Purchased power		35		48		81		134
Gas purchased for resale		4		8		55		64
Other operations and maintenance		218		233		682		691
Loss from regulatory disallowance		89		-		89		-
Depreciation and amortization		102		99		300		283
Taxes other than income taxes		85		82		234		218

Total operating expenses		782		675		2,123		1,831

Operating Income		333		385		586		672

Other Income and Expenses:
Miscellaneous income		16		23		45		64
Miscellaneous expense		2		8		8		11

Total other income		14		15		37		53
Interest Charges		54		56		153		158

Income Before Income Taxes		293		344		470		567
Income Taxes		102		120		166		200

Net Income		191		224		304		367
Preferred Stock Dividends		1		1		3		4

Net Income Available to Common Stockholder	$	190	$	223	$	301	$	363

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

UNION ELECTRIC COMPANY

BALANCE SHEET

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


	September 30, 2011		December 31, 2010
ASSETS

Current Assets:
Cash and cash equivalents	$	356	$	202
Accounts receivable – trade (less allowance for doubtful accounts of $7 and $8, respectively)		308		217
Accounts receivable – affiliates		1		6
Unbilled revenue		131		159
Miscellaneous accounts and notes receivable		35		116
Materials and supplies		337		341
Current regulatory assets		103		179
Other current assets		68		55

Total current assets		1,339		1,275

Property and Plant, Net		9,796		9,775
Investments and Other Assets:
Nuclear decommissioning trust fund		330		337
Intangible assets		5		2
Regulatory assets		694		694
Other assets		474		421

Total investments and other assets		1,503		1,454

TOTAL ASSETS	$	12,638	$	12,504

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Current maturities of long-term debt	$	178	$	5
Accounts and wages payable		160		326
Accounts payable – affiliates		48		75
Taxes accrued		131		76
Interest accrued		72		63
Current regulatory liabilities		55		23
Current accumulated deferred income taxes, net		19		43
Other current liabilities		82		89

Total current liabilities		745		700

Long-term Debt, Net		3,777		3,949
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		2,148		1,908
Accumulated deferred investment tax credits		71		78
Regulatory liabilities		804		766
Asset retirement obligations		334		363
Pension and other postretirement benefits		352		369
Other deferred credits and liabilities		172		218

Total deferred credits and other liabilities		3,881		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		2,089		2,007

Total stockholders’ equity		4,235		4,153

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	12,638	$	12,504

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

UNION ELECTRIC COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Nine Months Ended September 30,
	2011		2010
Cash Flows From Operating Activities:
Net income	$	304	$	367
Adjustments to reconcile net income to net cash provided by operating activities:
Loss from regulatory disallowance		89		-
Depreciation and amortization		300		283
Amortization of nuclear fuel		51		36
Amortization of debt issuance costs and premium/discounts		5		2
Deferred income taxes and investment tax credits, net		203		266
Allowance for equity funds used during construction		(22)		(38)
Other		1		9
Changes in assets and liabilities:
Receivables		(46)		(160)
Materials and supplies		2		10
Accounts and wages payable		(142)		(96)
Taxes accrued		51		118
Assets, other		56		(148)
Liabilities, other		1		77
Pension and other postretirement benefits		2		(5)
Taum Sauk insurance recoveries, net of costs		(1)		57

Net cash provided by operating activities		854		778

Cash Flows From Investing Activities:
Capital expenditures		(402)		(445)
Nuclear fuel expenditures		(45)		(24)
Purchases of securities – nuclear decommissioning trust fund		(163)		(207)
Sales of securities – nuclear decommissioning trust fund		147		195
Other		4		-

Net cash used in investing activities		(459)		(481)

Cash Flows From Financing Activities:
Dividends on common stock		(219)		(176)
Dividends on preferred stock		(3)		(4)
Capital issuance costs		-		(4)
Redemptions, repurchases, and maturities:
Long-term debt		-		(66)
Preferred stock		-		(33)
Generator advances for construction received (refunded)		(19)		10

Net cash used in financing activities		(241)		(273)

Net change in cash and cash equivalents		154		24
Cash and cash equivalents at beginning of year		202		267

Cash and cash equivalents at end of period	$	356	$	291

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

AMEREN ILLINOIS COMPANY

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010 ^(a)		2011		2010 ^(a)
Operating Revenues:
Electric	$	631	$	632	$	1,556	$	1,630
Gas		114		114		619		674
Other		-		-		1		-

Total operating revenues		745		746		2,176		2,304


Operating Expenses:
Purchased power		270		286		677		782
Gas purchased for resale		43		42		358		401
Other operations and maintenance		152		155		501		476
Depreciation and amortization		55		52		161		158
Taxes other than income taxes		29		29		96		95

Total operating expenses		549		564		1,793		1,912

Operating Income		196		182		383		392

Other Income and Expenses:
Miscellaneous income		2		2		5		6
Miscellaneous expense		2		2		4		6

Total other income		-		-		1		-
Interest Charges		33		37		103		108

Income Before Income Taxes		163		145		281		284
Income Taxes		65		54		111		109

Income from Continuing Operations		98		91		170		175
Income from Discontinued Operations, net of tax		-		19		-		40

Net Income		98		110		170		215
Preferred Stock Dividends		-		1		2		4

Net Income Available to Common Stockholder	$	98	$	109	$	168	$	211

^(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.

AMEREN ILLINOIS COMPANY

BALANCE SHEET

(Unaudited) (In millions)


	September 30, 2011		December 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	116	$	322
Accounts receivable – trade (less allowance for doubtful accounts of $13 and $13, respectively)		194		230
Accounts receivable – affiliates		9		73
Unbilled revenue		122		205
Miscellaneous accounts and notes receivable		73		44
Materials and supplies		239		198
Current regulatory assets		247		260
Other current assets		108		106

Total current assets		1,108		1,438

Property and Plant, Net		4,699		4,576
Investments and Other Assets:
Tax receivable – Genco		61		72
Goodwill		411		411
Regulatory assets		571		747
Other assets		214		162

Total investments and other assets		1,257		1,392

TOTAL ASSETS	$	7,064	$	7,406

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Current maturities of long-term debt	$	-	$	150
Accounts and wages payable		135		182
Accounts payable – affiliates		58		82
Taxes accrued		12		26
Interest accrued		46		27
Customer deposits		80		83
Mark-to-market derivative liabilities		73		82
Mark-to-market derivative liabilities – affiliates		166		172
Environmental remediation		57		72
Current regulatory liabilities		68		76
Other current liabilities		58		63

Total current liabilities		753		1,015

Long-term Debt, Net		1,658		1,657
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		925		724
Accumulated deferred investment tax credits		7		8
Regulatory liabilities		660		553
Pension and other postretirement benefits		328		413
Other deferred credits and liabilities		231		460

Total deferred credits and other liabilities		2,151		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		471		542
Accumulated other comprehensive income		17		20

Total stockholders’ equity		2,502		2,576

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	7,064	$	7,406

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

AMEREN ILLINOIS COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Nine Months Ended September 30,
	2011		2010 ^(a)
Cash Flows From Operating Activities:
Net income	$	170	$	215
Income from discontinued operations, net of tax		-		(40)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		161		158
Amortization of debt issuance costs and premium/discounts		6		9
Deferred income taxes and investment tax credits, net		202		143
Other		(7)		(5)
Changes in assets and liabilities:
Receivables		104		(16)
Materials and supplies		(41)		(31)
Accounts and wages payable		(58)		(41)
Taxes accrued		(14)		22
Assets, other		24		(76)
Liabilities, other		(11)		14
Pension and other postretirement benefits		(98)		(6)
Operating cash flows provided by discontinued operations		-		113

Net cash provided by operating activities		438		459

Cash Flows From Investing Activities:
Capital expenditures		(261)		(215)
Returns from (advances to) ATXI for construction		49		(7)
Proceeds from intercompany note receivable – Genco		-		45
Net investing activities used in discontinued operations		-		(6)

Net cash used in investing activities		(212)		(183)

Cash Flows From Financing Activities:
Dividends on common stock		(238)		(100)
Dividends on preferred stock		(2)		(4)
Capital issuance costs		-		(4)
Redemptions, repurchases, and maturities:
Long-term debt		(150)		(40)
Preferred stock		-		(19)
Capital contribution from parent		6		-
Generator advances for construction refunded, net of receipts		(53)		(28)
Other		5		5
Net financing activities used in discontinued operations		-		(107)


Net cash used in financing activities		(432)		(297)

Net change in cash and cash equivalents		(206)		(21)
Cash and cash equivalents at beginning of year		322		306

Cash and cash equivalents at end of period	$	116	$	285

^(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.

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF INCOME (LOSS)

(Unaudited) (In millions)

		$327		$327		$327		$327
	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Operating Revenues	$	327	$	335	$	828	$	877

Operating Expenses:
Fuel		169		146		410		405
Purchased power		37		42		55		62
Other operations and maintenance		48		47		137		141
Goodwill, impairment and other charges		35		170		36		170
Depreciation and amortization		24		25		73		74
Taxes other than income taxes		4		4		16		17

Total operating expenses		317		434		727		869

Operating Income (Loss)		10		(99)		101		8

Other Income and Expenses:
Miscellaneous income		1		-		1		1
Miscellaneous expense		-		-		-		1

Total other income		1		-		1		-
Interest Charges		16		21		47		60

Income (Loss) Before Income Taxes		(5)		(120)		55		(52)
Income Taxes (Benefit)		(1)		(20)		24		10

Net Income (Loss)		(4)		(100)		31		(62)
Less: Net Income Attributable to Noncontrolling Interest		1		1		2		3

Net Income (Loss) Attributable to Ameren Energy Generating Company	$	(5)	$	(101)	$	29	$	(65)

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

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions, except share data)


	September 30, 2011		December 31, 2010
ASSETS

Current Assets:
Cash and cash equivalents	$	8	$	6
Advances to money pool		63		25
Accounts receivable – affiliates		82		126
Miscellaneous accounts and notes receivable		33		19
Materials and supplies		118		130
Mark-to-market derivative assets		10		26
Other current assets		8		4

Total current assets		322		336

Property and Plant, Net		2,219		2,248
Investments and Other Assets:
Intangible assets		-		3
Other assets		16		24

Total investments and other assets		16		27

TOTAL ASSETS	$	2,557	$	2,611

LIABILITIES AND EQUITY
Current Liabilities:
Accounts and wages payable	$	58	$	62
Accounts payable – affiliates		9		23
Current portion of tax payable – Ameren Illinois		9		8
Taxes accrued		14		20
Interest accrued		27		13
Mark-to-market derivative liabilities		3		9
Mark-to-market derivative liabilities – affiliates		-		5
Current accumulated deferred income taxes, net		13		13
Other current liabilities		15		12

Total current liabilities		148		165

Credit Facility Borrowings		-		100
Long-term Debt, Net		824		824
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		313		253
Accumulated deferred investment tax credits		3		3
Tax payable – Ameren Illinois		61		72
Asset retirement obligations		69		74
Pension and other postretirement benefits		83		88
Other deferred credits and liabilities		14		23

Total deferred credits and other liabilities		543		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		422		393
Accumulated other comprehensive loss		(42)		(44)

Total Ameren Energy Generating Company stockholder’s equity		1,029		998
Noncontrolling Interest		13		11

Total equity		1,042		1,009

TOTAL LIABILITIES AND EQUITY	$	2,557	$	2,611

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

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Nine Months Ended September 30,
	2011		2010
Cash Flows From Operating Activities:
Net income (loss)	$	31	$	(62)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Goodwill, impairment and other charges		36		170
Loss on sales of emission allowances		-		3
Gain on sales of properties		(12)		(5)
Net mark-to-market (gain) loss on derivatives		5		(2)
Depreciation and amortization		75		87
Amortization of debt issuance costs and premium/discounts		2		2
Deferred income taxes and investment tax credits, net		58		5
Changes in assets and liabilities:
Receivables		9		55
Materials and supplies		6		43
Accounts and wages payable		(16)		(20)
Taxes accrued		(6)		10
Assets, other		3		8
Liabilities, other		(9)		(4)
Pension and other postretirement benefits		(3)		3

Net cash provided by operating activities		179		293

Cash Flows From Investing Activities:
Capital expenditures		(112)		(71)
Proceeds from sales of properties		49		18
Money pool advances, net		(38)		(132)

Net cash used in investing activities		(101)		(185)

Cash Flows From Financing Activities:
Capital issuance costs		-		(4)
Credit facility repayments, net		(100)		-
Note payable – affiliates		-		(103)
Capital contribution from parent		24		-

Net cash used in financing activities		(76)		(107)

Net change in cash and cash equivalents		2		1
Cash and cash equivalents at beginning of year		6		6

Cash and cash equivalents at end of period	$	8	$	7

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

AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY

AMEREN ILLINOIS COMPANY (Consolidated)

AMEREN ENERGY GENERATING COMPANY (Consolidated)

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

September 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 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 in the Form 10-Q for the quarter ended June 30, 2011. 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 nine months ended September 30, 2011, and 2010. The number of restricted stock shares and performance share units outstanding had an immaterial impact on earnings per share.

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.

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. The amended guidance will not impact 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.

Testing of Goodwill for Impairment

In September 2011, FASB amended its guidance for the testing of goodwill impairment. The amendments allow the option to make a qualitative evaluation about the likelihood of goodwill impairment to determine whether an estimated fair value of a reporting unit should be calculated. If the qualitative evaluation yields support that the fair value of the reporting unit exceeds its carrying value, the quantitative impairment test is not required. This guidance will become effective for periods starting after December 31, 2011. Early adoption of the guidance is permitted, and Ameren and Ameren Illinois anticipate adopting the guidance for the annual goodwill impairment test performed as of October 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 September 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. During the third quarter of 2010, Ameren and Genco each recorded a noncash goodwill impairment charge, which was reflected in “Goodwill, impairment and other charges” in their statements of income. See Note 17 - Goodwill and Other Asset Impairments under Part II, Item 8, of the Form 10-K for additional information about the prior-year impairment charge.

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 created new allowances for SO ₂ and NO _x emissions, and restricted the use of pre-existing SO ₂ and 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 of $2 million and $1 million, respectively, which was reflected in “Goodwill, impairment and other charges” on their

statements of income. Ameren Missouri recorded a $1 million impairment of its SO ₂ emission allowances by reducing a previously established regulatory liability relating to the SO ₂ emission allowances, which had no impact to earnings. See Note 9 - Commitments and Contingencies for additional information on emission allowances and the CSAPR. During the third quarter of 2010, Ameren and Genco each recognized an impairment charge of its intangible assets to reduce the carrying value of their SO ₂ emission allowances. The charge was reflected in “Goodwill, impairment and other charges” in their statements of income. See Note 17 - Goodwill and Other Asset Impairments under Part II, Item 8, of the Form 10-K for additional information about the prior-year impairment charge.

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 nine months ended September 30, 2011, and 2010. The table below does not include the intangible asset impairment charges referenced above.


	Three Months						Nine Months
	2011			2010			2011			2010
Ameren ^(a)	$	(b	)	$	10		$	2		$	20
Ameren Missouri		-			(b	)		-			(b	)
Genco ^(a)		(b	)		8			2			16
AERG ^(a)		(b	)		2			(b	)		4

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

(b)	Less than $1 million.

At September 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 September 30, 2011, was $5 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 nine months ended September 30, 2011, and 2010:


	Three Months				Nine Months
	2011		2010		2011		2010
Ameren Missouri	$	47	$	45	$	110	$	103
Ameren Illinois		10		9		42		41
Ameren	$	57	$	54	$	152	$	144

Uncertain Tax Positions

The amount of unrecognized tax benefits as of September 30, 2011, was $189 million, $144 million, $30 million, and $11 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of September 30, 2011, that would impact the effective tax rate, if recognized, was $3 million, $1 million, less than $(1) million and $1 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

In the second quarter of 2011, final settlement for the years 2005 and 2006 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 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. Ameren’s federal income tax return for the year 2010 is currently under examination.

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

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the nine months ended September, 30 2011:


	Ameren ^(a)(b)			Ameren Missouri ^(b)			Ameren Illinois ^(c ⁾			Genco			AERG
Balance at December 31, 2010	$	475		$	363		$	3		$	74		$	35
Liabilities incurred		(d	)		-			-			(d	)		-
Liabilities settled		(2	)		(1	)		(d	)		(1	)		(d	)
Accretion in 2011 ^(e)		21			16			(d	)		4			1
Change in estimates ^(f)		(49	)		(44	)		(d	)		(2	)		(3	)
Balance at September 30, 2011	$	445	^(g)	$	334		$	3		$	75	^(g)	$	33

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

(b)	The nuclear decommissioning trust fund assets of $330 million and $337 million as of September 30, 2011, and December 31, 2010, respectively, were restricted for decommissioning of the Callaway energy center.

(c)	Balance included in “Other deferred credits and liabilities” on the balance sheet.

(d)	Less than $1 million.

(e)	Accretion expense was recorded as an increase to regulatory assets at Ameren Missouri and Ameren Illinois.

(f)

Ameren Missouri changed estimates related to its Callaway energy center decommissioning costs because of a cost study performed in 2011 and a decline in the cost escalation factor assumptions. Ameren Missouri and Genco changed estimates related to retirement costs for asbestos removal and river structures. Additionally, Genco and AERG changed estimates related to retirement costs for their coal combustion byproduct storage areas.

(g)	Balance included $6 million in “Other current liabilities” on the balance sheet as of September 30, 2011.

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 nine months ended September 30, 2011, and 2010, is shown below:


	Three Months						Nine Months
	2011			2010			2011			2010
Ameren:
Noncontrolling interest, beginning of period	$	155		$	206		$	154		$	204
Net income attributable to noncontrolling interest		2			3			6			10
Dividends paid to noncontrolling interest holders		(2	)		(2	)		(5	)		(7	)
Purchase of subsidiary preferred shares from noncontrolling interests ^(a)		-			(52	)		-			(52	)
Noncontrolling interest, end of period	$	155		$	155		$	155		$	155
Genco:
Noncontrolling interest, beginning of period	$	12		$	11		$	11		$	9
Net income attributable to noncontrolling interest		1			1			2			3
Noncontrolling interest, end of period	$	13		$	12		$	13		$	12

(a)	Represents preferred stock redemptions of $33 million and $19 million by Ameren Missouri and CILCO, respectively.

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.

Closure of Meredosia and Hutsonville Energy Centers

On October 4, 2011, Resources Company announced that a total of four currently operating units at Genco’s Meredosia and Hutsonville energy centers will cease operating at the end of 2011. The closure of these units will result in the elimination of 90 positions. Ameren and Genco each recorded the following pretax charges to earnings during the third quarter of 2011 related to the planned closure of these energy centers:

•

a $26 million non-cash impairment of plant book value;

•

a $5 million non-cash impairment of materials and supplies; and

•

a $4 million estimate for future cash severance costs.

These charges were recorded in Ameren’s and Genco’s statements of income as “Goodwill, impairment and other charges” and were included in the Merchant Generation segment results. Ameren and Genco anticipate that substantially all of the severance will be paid during the first quarter of 2012.

Ameren and Genco expect to receive cash tax benefits of $22 million and $33 million, respectively, as a result of the closure of these units. Previously recorded AROs for ash pond closures, and river structure and asbestos removals, for these energy centers were $38 million. Ameren and Genco expect cash expenditures over the next ten years along with associated cash tax benefits of $16 million.

The closure of these units is primarily the result of the expected cost of complying with the CSAPR, which was issued in July 2011. Genco determined that CSAPR compliance options for these four units were uneconomical. Another factor driving the closure of these facilities was a lack of a multi-year capacity market managed by MISO, without which Genco was not positioned to make the substantial investment for environmental controls that would be required to keep these units in service.

In addition, during the third quarter of 2010, Ameren and Genco each recognized long-lived asset impairment charges. See Note 17 - Goodwill and Other Asset Impairments under Part II, Item 8, of the Form 10-K for additional information about the prior-year impairment charge.

Employee Separation

On October 21, 2011, Ameren announced that, as part of its efforts to reduce its operations and maintenance expenses, it was extending a voluntary separation offer to approximately 715 management and labor union-represented employees who are 58 years of age or older as of December 31, 2011. This program is being offered to eligible employees at Ameren Missouri and at Ameren Services. Employees who accept the separation offer will receive benefits consistent with Ameren’s standard management severance benefits. Employees must decide whether to accept the separation offer by December 22, 2011, and those accepting are expected to leave their employment by December 31, 2011.

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 County Circuit Court), and the Cole County case was dismissed. In September 2009, the Stoddard County Circuit Court granted Noranda’s request to stay the electric rate increase granted by the January 2009 MoPSC order as it applies specifically to Noranda’s electric service account until the court renders its decision on the appeal. From the granting of the stay request until June 2010, Noranda paid into the Stoddard County 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 County Circuit Court’s registry. Noranda continued to pay into the Stoddard County 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 would be the last possible contested amount that could be deposited into the Stoddard County Circuit Court’s registry relating to this 2009 electric rate order appeal. As of September 30, 2011, the aggregate amount held in the Stoddard County Circuit Court’s registry was $18 million.

In August 2010, the Stoddard County Circuit Court issued a judgment that reversed parts of the MoPSC’s decision. Also, upon issuance, the Stoddard County Circuit Court suspended its own judgment. Therefore, the entire amount held in the Stoddard County Circuit Court’s registry will remain in the Stoddard County 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. In November 2011, the Missouri Court of Appeals issued a ruling that upheld the MoPSC’s January 2009 electric rate order; thereby reversing the Stoddard County Circuit Court’s August 2010 decision. Noranda and MoOPC could request further appeals by early 2012. If the MoPSC’s January 2009 electric rate order is ultimately upheld, Ameren Missouri will receive all of the funds held in the Stoddard County Circuit Court’s registry, plus accrued interest. As a result of the Missouri Court of Appeals ruling, Ameren Missouri anticipates that the Stoddard County Circuit Court will release to Ameren Missouri the amount held in its registry by early 2012, depending on additional court proceedings.

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 base rate billings under 2010 electric rates and 2007 electric rates, as well as their FAC amounts to the extent those billings relate to service prior to the effective date of the new rates established by the 2011 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, the four industrial customers will continue to pay a portion of their FAC payments to the Cole County Circuit Court’s registry to the extent those payments relate to service prior to the effective date of the new rates by the 2011 electric rate order. It is expected that a portion of the FAC billings invoiced to these customers in September 2012 will be the last contested amount deposited into the Cole County Circuit Court’s registry relating to this 2010 electric rate order appeal. As of September 30, 2011, the aggregate amount held by the Cole County Circuit Court, excluding the bond amount, was $14 million. A decision is expected to be issued on the MIEC’s and MoOPC’s appeal by the Cole County Circuit Court in 2011 or early 2012.

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.

2011 Electric Rate Order

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 new rates established in 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 each recorded a pretax charge to earnings of $89 million, relating to the Taum Sauk disallowance, in the quarter ended September 30, 2011. This charge was recorded on Ameren’s statement of income as “Goodwill, impairment and other charges” and recorded on Ameren Missouri’s statement of income as “Loss from regulatory disallowance.”

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 July 31, 2011 ⁽ ^a)			Recovery Period Ends
Demand-side costs ⁽ ^b ⁾	$	33			July 2017
Construction accounting for pollution control equipment ⁽ ^b ⁾		25			Sept. 2033
SO ₂ emissions allowances sales tracker ⁽ ^c ⁾		8			July 2013
FERC-ordered MISO resettlements ⁽ ^c ⁾		2			July 2013
2006 Storm costs ⁽ ^c ⁾		1			July 2013
Vegetation management and infrastructure inspection ⁽ ^c ⁾		(3	)		July 2013
Pension and postretirement benefit cost tracker for 2010 costs ⁽ ^b ⁾		(11	)		July 2016
Total	$	55

(a)	Represents amounts capitalized at implementation of the rate order at July 31, 2011, and excludes the impact of subsequent amortization of the regulatory assets or liabilities.

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

(c)	Previous recovery period was extended.

On July 1, 2011, a new law took effect that reformed the judicial appeal process for 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 rates. Such rate revisions could be ordered to be applied retroactively. The provisions of this new law 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 a rehearing request of various aspects of the order including the disallowance of Taum Sauk enhancements. The MoPSC denied the requests. Subsequently, Ameren Missouri appealed the disallowance of Taum Sauk enhancements to the Missouri Court of Appeals, Western District. MIEC also appealed certain aspects of the MoPSC’s electric rate order to the Missouri Court of Appeals, Western District. A decision is expected by the Missouri Court of Appeals, Western District, in 2012. Ameren Missouri cannot predict the ultimate outcome of these appeals.

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. In October 2011, Ameren Missouri began refunding the $18 million to customers, through the FAC.

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 late 2011 or in 2012. 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 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 MoPSC’s FAC prudence review for the period from October 1, 2009, to May 31, 2011, was initiated in September 2011. On October 28, 2011, the MoPSC staff filed a recommendation with the MoPSC to direct Ameren Missouri to refund to customers, prior to the completion of the staff’s prudence review, the pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC staff calculated these pretax earnings to be $26 million. We cannot predict whether the MoPSC will approve this recommendation. 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. Because of pending court appeals and regulatory review, Ameren Missouri does not believe these amounts are currently probable of refund to customers.

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, seeks to increase annual revenues for electric delivery service by $39 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 February 2011, Ameren Illinois also filed a request with the ICC to increase its annual revenues for natural gas delivery service. The currently pending request, as revised, 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 $956 million.

In an attempt to reduce regulatory lag, Ameren Illinois used a future test year, 2012, in each of these rate requests.

In its response to Ameren Illinois’ rate increase requests the ICC staff recommended an increase in annual revenues for electric delivery service of $4 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 an increase in annual revenues for natural gas delivery service of $29 million, based on an 8.9% return on equity, a capital structure composed of 51.8% common equity, and a rate base of $945 million. Other parties also made recommendations through testimony filed in the electric and natural gas delivery service rate cases.

A decision by the ICC in these proceedings is required in 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.

In October 2011, as discussed below, the Energy Infrastructure Modernization Act was enacted in Illinois. Ameren Illinois plans to participate by adopting the performance-based formula process of the law and by withdrawing its pending electric delivery service rate case.

Energy Infrastructure Modernization Act

In October 2011, the Energy Infrastructure Modernization Act was enacted into law and became effective immediately. Also, in October 2011, House Bill 3036, which, if enacted, would result in certain amendments to the Energy Infrastructure Modernization Act, was passed by the Illinois General Assembly. The Energy Infrastructure Modernization Act applies to certain electric utilities in Illinois on an opt-in basis. This law includes a performance-based formula process for determining rates that would provide for the recovery of actual costs of electric delivery service that are prudently incurred, reflect the utility’s actual regulated capital structure and include a formula for calculating the return on equity component of the cost of capital. House Bill 3036 modified the equity component of the formula rate to be based on the yields of 30-year United States treasury bonds plus 580 basis points, instead of 600 basis points. Participating utilities are subject to certain performance standards whereby the failure to achieve the standards will result in a reduction in the utility’s allowed return on equity calculated under the formula. Ameren Illinois would be required to invest $625 million in capital expenditures incremental to Ameren Illinois’ average capital expenditures for calendar years 2008 through 2010 over the next ten years to modernize its distribution system. Such investments are expected to encourage economic development and create an estimated 450 additional jobs within Illinois. Ameren Illinois also will be required to make a one-time $7.5 million non-recoverable donation to the Illinois Science and Energy Innovation Trust, as well as a $1 million annual donation to the trust for as long as it is under the formula ratemaking process. House Bill 3036 also would require Ameren Illinois to contribute $1 million annually for customer assistance programs for as long as it is under the formula ratemaking process, as well as require Ameren Illinois to withdraw its pending electric delivery service rate case. To become law, House Bill 3036 must be approved by the Illinois Governor, or if the Illinois Governor elects to veto the legislation, the Illinois General Assembly would have to override the veto. The formula ratemaking process is effective until the end of 2017, but could be extended by the Illinois General Assembly for an additional five years. Ameren Illinois is reviewing the final version of this law and House Bill 3036 to determine their potential impacts on Ameren’s and Ameren Illinois’ results of operations, financial position, and liquidity.

The Energy Infrastructure Modernization Act does not apply to natural gas utilities.

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. The two projects are the Illinois River project and the Big Muddy project. These initial projects, subject to MISO approval, consist of a potential $1 billion investment in high voltage transmission assets in Illinois and Missouri. MISO approval for the Illinois River project as well as two additional projects is anticipated in December 2011. The FERC order approved the following rate mechanisms with respect to ATX’s Illinois River and Big Muddy 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 September 30, 2011, Ameren Missouri had capitalized approximately $68 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 following tables summarize the borrowing activity and relevant interest rates under credit facilities as of September 30, 2011, and excludes issued letters of credit:

		Ameren (Parent)			Ameren (Parent)			Ameren (Parent)
2010 Missouri Credit Agreement ($800 million)	Ameren (Parent)			Ameren Missouri			Total
Average daily borrowings outstanding during 2011	$	140		$	-		$	140
Outstanding credit facility borrowings at period end		-			-			-
Weighted-average interest rate during 2011		2.30	%		-			2.30	%
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	$	-		$	55		$	55
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	%

(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 nine months of 2011 were $440 million.

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

The 2010 Credit Agreements are used for cash borrowings, to issue letters of credit, and to support borrowings under Ameren’s $500 million commercial paper program, Ameren Missouri’s $500 million commercial paper program and Ameren Illinois’ $500 million commercial paper program, the latter of which was created in October 2011. Any of the 2010 Credit Agreements are available to Ameren to support borrowings under Ameren’s commercial paper program, subject to borrowing sublimits. The 2010 Missouri Credit Agreement is available to support borrowings under Ameren Missouri’s commercial paper program, and the 2010 Illinois Credit Agreement is available to support borrowings under Ameren Illinois’ commercial paper program. At September 30, 2011, Ameren had $330 million of commercial paper outstanding and $15 million of letters of credit outstanding, and Ameren Missouri and Ameren Illinois had no commercial paper or letters of credit outstanding. Based on outstanding borrowings and letters of credit issued under the 2010 Credit Agreements as of September 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 September 30, 2011, was $1.8 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

At September 30, 2011, Ameren had $330 million of commercial paper outstanding. During the first nine months of 2011, Ameren had average daily commercial paper balances outstanding of $335 million with a weighted-average interest rate of 0.85%. The peak short-term commercial paper outstanding and peak interest rate during the first nine months of 2011 were $435 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 September 30, 2011, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 48%, 46%, 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 September 30, 2011, was 4.9 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 September 30, 2011, Ameren’s consolidated indebtedness ratio, calculated in accordance with the provisions of the $20 Million Facility, was 48%. Failure by Ameren to satisfy this covenant would constitute an immediate default under the $20 Million Facility but, given the size of the facility, would not trigger an Ameren default under any of the 2010 Credit Agreements or Ameren’s indenture.

None of the Ameren Companies’ credit agreements or other financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At September 30, 2011, the Ameren Companies were in compliance with the provisions and covenants of their credit agreements.

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 nine months ended September 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 September 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 nine months ended September 30, 2011, was 0.83% and 0.89%, respectively (2010 - 0.34% and 0.65%, 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 nine months ended September 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 $17 million and 1.8 million new shares valued at $49 million in the three and nine months ended September 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.

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 September 30, 2011, at an assumed interest rate of 6% and dividend rate of 7%.


	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	³ 2.0		3.3	$	2,115		³ 2.5		89.3	$	1,696
Ameren Illinois	³ 2.0		7.5		3,264	^(d)	³ 1.5		3.3		203

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

(b)	Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $89 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 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 September 30, 2011, Ameren Illinois’ ratio of common stock equity to total capitalization was 59%.

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 September 30, 2011:

Required Interest
Coverage Ratio

Actual Interest
Coverage Ratio

Required Debt-to-

Capital Ratio

Actual Debt-to-

Capital Ratio

Genco

³ 1.75 ^(a) /2.50 ^(b)

4.5

£ 60% ^(b)

44%

(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, for borrowed money. 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.

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 September 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 the components of “Other Income and Expenses” in the Ameren Companies’ statements of income for the three and nine months ended September 30, 2011, and 2010:


	Three Months				Nine Months
	2011		2010		2011		2010
Ameren: ^(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	10	$	14	$	25	$	40
Interest income on industrial development revenue bonds		7		7		21		21
Interest and dividend income		1		2		3		4
Other		-		1		2		5
Total miscellaneous income	$	18	$	24	$	51	$	70
Miscellaneous expense:
Donations	$	1	$	7	$	4	$	10
Other		4		3		11		9
Total miscellaneous expense	$	5	$	10	$	15	$	19
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	8	$	13	$	22	$	38
Interest income on industrial development revenue bonds		7		7		21		21
Interest and dividend income		-		2		1		3
Other		1		1		1		2
Total miscellaneous income	$	16	$	23	$	45	$	64
Miscellaneous expense:
Donations	$	1	$	7	$	3	$	8
Other		1		1		5		3
Total miscellaneous expense	$	2	$	8	$	8	$	11
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	2	$	-	$	3	$	1
Interest and dividend income		-		1		-		2
Other		-		1		2		3
Total miscellaneous income	$	2	$	2	$	5	$	6
Miscellaneous expense:
Donations	$	1	$	1	$	1	$	2
Other		1		1		3		4
Total miscellaneous expense	$	2	$	2	$	4	$	6
Genco:
Miscellaneous income:
Other	$	1	$	-	$	1	$	1
Total miscellaneous income	$	1	$	-	$	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:

•

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 September 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)
Ameren Missouri		122			46			(e	)		(e	)		(e	)		(e	)		(e	)		(e	)
Genco		27			21			(e	)		(e	)		(e	)		(e	)		(e	)		(e	)
Other ^(f)		8			6			(e	)		(e	)		(e	)		(e	)		(e	)		(e	)
Ameren		157			73			(e	)		(e	)		(e	)		(e	)		(e	)		(e	)
Heating oil (in gallons)
Ameren Missouri		(e	)		(e	)		(e	)		(e	)		(e	)		(e	)		62			80
Genco		(e	)		(e	)		(e	)		(e	)		33			43			(e	)		(e	)
Other ^(f)		(e	)		(e	)		(e	)		(e	)		10			12			(e	)		(e	)
Ameren		(e	)		(e	)		(e	)		(e	)		43			55			62			80
Natural gas (in mmbtu)
Ameren Missouri		9			13			(e	)		(e	)		1			2			19			21
Ameren Illinois		51			85			(e	)		(e	)		(e	)		(e	)		188			173
Genco		(e	)		(e	)		(e	)		(e	)		5			3			(e	)		(e	)
Other ^(f)		(e	)		(e	)		(e	)		(e	)		20			16			(e	)		(e	)
Ameren		60			98			(e	)		(e	)		26			21			207			194
Power (in megawatthours)
Ameren Missouri		1			2			(e	)		(e	)		-			1			5			5
Ameren Illinois		12			(e	)		(e	)		(e	)		(e	)		(e	)		27			26
Genco		(e	)		(e	)		(e	)		(e	)		-			3			(e	)		(e	)
Other ^(f)		60			61			17			2			32			57			(11	)		(13	)
Ameren		73			63			17			2			32			61			21			18
Uranium (pounds in thousands)
Ameren Missouri & Ameren		5,710			5,810			(e	)		(e	)		(e	)		(e	)		308			185

(a)	Contracts through December 2017, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of September 30, 2011.

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

(c)	Contracts through October 2014, December 2012, and April 2015 for heating oil, natural gas, and power, respectively, as of September 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 September 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.

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 September 30, 2011, and December 31, 2010:

	Ameren Missouri		Ameren Missouri		Ameren Missouri			Ameren Missouri			Ameren Missouri
	Balance Sheet Location	Ameren ^(a)		Ameren Missouri			Ameren Illinois			Genco
2011:
Derivative assets designated as hedging instruments
Commodity contracts:
Power	MTM derivative assets	$	7	$	(b	)	$	(b	)	$	-
	Other assets		3		-			-			-
	Total assets	$	10	$	-		$	-		$	-
Derivative liabilities designated as hedging instruments
Commodity contracts:
Power	MTM derivative liabilities	$	3	$	(b	)	$	-		$	-
	Other deferred credits and liabilities		8		-			-			-
	Total liabilities	$	11	$	-		$	-		$	-
Derivative assets not designated as hedging instruments ^(c)
Commodity contracts:
Heating oil	MTM derivative assets	$	28	$	(b	)	$	(b	)	$	9
	Other current assets		-		17			-			-
	Other assets		9		6			-			2
Natural gas	MTM derivative assets		6		(b	)		(b	)		1
	Other current assets		-		-			2			-
	Other assets		-		-			-			-
Power	MTM derivative assets		53		(b	)		(b	)		-
	Other current assets		-		23			1			-
	Other assets		104		2			87			-
	Total assets	$	200	$	48		$	90		$	12
Derivative liabilities not designated as hedging instruments ^(c)
Commodity contracts:
Heating oil	MTM derivative liabilities	$	4	$	(b	)	$	-		$	2
	Other current liabilities		-		2			-			-
	Other deferred credits and liabilities		3		1			-			1
Natural gas	MTM derivative liabilities		84		(b	)		69			1
	Other current liabilities		-		10			-			-
	Other deferred credits and liabilities		66		10			55			-
Power	MTM derivative liabilities		27		(b	)		4			-
	MTM derivative liabilities - affiliates		-		(b	)		166			-
	Other current liabilities		-		5			-			-
	Other deferred credits and liabilities		13		1			52			-
Uranium	Other deferred credits and liabilities		1		1			-			-
	Total liabilities	$	198	$	30		$	346		$	4
2010:
Derivative assets designated as hedging instruments
Commodity contracts:
Power	MTM derivative assets	$	3	$	(b	)	$	(b	)	$	-
	Other assets		2		-			-			-
	Total assets	$	5	$	-		$	-		$	-
Derivative liabilities designated as hedging instruments
Commodity contracts:
Power	MTM derivative liabilities	$	1	$	(b	)	$	-		$	-
	Total liabilities	$	1	$	-		$	-		$	-
Derivative assets not designated as hedging instruments ^(c)
Commodity contracts:
Heating oil	MTM derivative assets	$	42	$	(b	)	$	(b	)	$	14
	Other current assets		-		24			-			-
	Other assets		22		13			-			7
Natural gas	MTM derivative assets		4		(b	)		(b	)		1
	Other current assets		-		1			1			-
	Other assets		1		-			1			-
Power	MTM derivative assets		78		(b	)		(b	)		11
	Other current assets		-		8			2			-
	Other assets		20		-			6			-

	Ameren Missouri		Ameren Missouri			Ameren Missouri			Ameren Missouri			Ameren Missouri
	Balance Sheet Location	Ameren ^(a)			Ameren Missouri			Ameren Illinois			Genco
Uranium	MTM derivative assets		2			(b	)		(b	)		-
	Other current assets		-			2			-			-
	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 September 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)		15			15			-			-			-
Natural gas derivative contracts ^(f)		(142	)		(20	)		(122	)		-			-
Power derivative contracts ^(g)		104			19			(134	)		-			219
Uranium derivative contracts ^(h)		(1	)		(1	)		-			-			-
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 September 30, 2011. Current gains of $3 million and $8 million were recorded at Ameren as of September 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 September 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 September 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 September 30, 2011. Current gains deferred as regulatory liabilities include $14 million and $14 million at Ameren and Ameren Missouri as of September 30, 2011, respectively. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri as of September 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 September 30, 2011. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Illinois, respectively, as of September 30, 2011. Current losses deferred as regulatory assets include $78 million, $9 million, and $69 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of September 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 September 30, 2011. Current gains deferred as regulatory liabilities include $24 million, $23 million, and $1 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of September 30, 2011. Current losses deferred as regulatory assets include $9 million, $4 million, and $170 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of September 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 September 30, 2011. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of September 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 September 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	$	-	$	167	$	2	$	2	$	24	$	4	$	-	$	-	$	199
AIC		-		-		119		-		1		-		1		-		121
Genco		-		19		1		-		8		-		2		-		30
Other ^(b)		272		12		7		6		33		287		-		60		677
Ameren	$	272	$	198	$	129	$	8	$	66	$	291	$	3	$	60	$	1,027
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.

The following table presents the amount of cash collateral held from counterparties, as of September 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		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 September 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 September 30, 2011, other collateral consisted of letters of credit in the amount of $10 million, $1 million, $2 million, and $7 million held by Ameren, Ameren Missouri, Genco, 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 September 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	$	-	$	158	$	-	$	1	$	18	$	3	$	-	$	-	$	180
AIC		-		-		119		-		-		-		-		-		119
Genco		-		12		-		-		3		-		2		-		17
Other ^(b)		272		9		7		4		20		171		-		59		542
Ameren	$	272	$	179	$	126	$	5	$	41	$	174	$	2	$	59	$	858
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)

(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 September 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 September 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	$	78	$	6		$ 53
Ameren Illinois		194		83		117
Genco		20		1		14
Other ^(c)		74		13		46
Ameren	$	366	$	103		$ 230
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.

(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 nine months ended September 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	$	(5	)	Operating Revenues - Electric	$	(1	)	Operating Revenues - Electric	$	(8	)
Interest rate ^(e)		-		Interest Charges		(f	)	Interest Charges		-
Genco:
Interest rate ^(e)		-		Interest Charges		(f	)	Interest Charges		-
2010:
Ameren: ^(d)
Power	$	5		Operating Revenues - Electric	$	(4	)	Operating Revenues - Electric	$	7
Interest rate ^(e)		-		Interest Charges		(f	)	Interest Charges		-
Genco:
Interest rate ^(e)		-		Interest Charges		(f	)	Interest Charges		-
Nine Months
2011:
Ameren: ^(d)
Power	$	(12	)	Operating Revenues - Electric	$	1		Operating Revenues - Electric	$	(6	)
Interest rate ^(e)		-		Interest Charges		(f	)	Interest Charges		-
Genco:
Interest rate ^(e)		-		Interest Charges		(f	)	Interest Charges		-
2010:
Ameren: ^(d)
Power	$	15		Operating Revenues - Electric	$	(18	)	Operating Revenues - Electric	$	(6	)
Interest rate ^(e)		-		Interest Charges		(f	)	Interest Charges		-
Genco:
Interest rate ^(e)		-		Interest Charges		(f	)	Interest Charges		-

(a)	Effective portion of gain (loss).

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

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

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

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

(f)	Less than $1 million.

Other Derivatives

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


		Location of Gain (Loss) Recognized in Income	Gain (Loss) Recognized in Income
			Three Months					Nine Months
			2011			2010		2011			2010
Ameren ^(a)	Heating oil	Operating Expenses - Fuel	$	(14	)	$	7	$	(4	)	$	1
	Natural gas (generation)	Operating Expenses - Fuel		-			-		-			(1	)
	Power	Operating Revenues - Electric		2			13		(5	)		33
		Total	$	(12	)	$	20	$	(9	)	$	33
Ameren Missouri	Natural gas (generation)	Operating Expenses - Fuel	$	-		$	-	$	(1	)	$	1
	Power	Operating Revenues - Electric		-			-		-			(1	)
		Total	$	-		$	-	$	(1	)	$	-
Genco	Heating oil	Operating Expenses - Fuel	$	(10	)	$	5	$	(3	)	$	1
	Natural gas (generation)	Operating Expenses - Fuel		1			1		1			-
	Power	Operating Revenues		(2	)		-		(3	)		1
		Total	$	(11	)	$	6	$	(5	)	$	2

(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 nine months ended September 30, 2011, and 2010:


		Gain (Loss) Recognized in Regulatory Liabilities or Regulatory Assets
		Three Months						Nine Months
		2011			2010			2011			2010
Ameren ^(a)	Heating oil	$	(20	)	$	10		$	(4	)	$	2
	Natural gas		(11	)		(46	)		23			(127	)
	Power		13			(21	)		103			2
	Uranium		1			2			(3	)		-
	Total	$	(17	)	$	(55	)	$	119		$	(123	)
Ameren Missouri	Heating oil	$	(20	)	$	10		$	(4	)	$	2
	Natural gas		-			(5	)		4			(16	)
	Power		(7	)		10			16			17
	Uranium		1			2			(3	)		-
	Total	$	(26	)	$	17		$	13		$	3
Ameren Illinois	Natural gas	$	(11	)	$	(41	)	$	19		$	(111	)
	Power		70			(59	)		218			(42	)
	Total	$	59		$	(100	)	$	237		$	(153	)

(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 September 30, 2011, and December 31, 2010:


		2011		2010
AIC	MTM derivative liabilities - affiliates	$	166	$	172
	Other deferred credits and liabilities		52		178
	Total	$	218	$	350

NOTE 7 - FAIR VALUE MEASUREMENTS

We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

See Note 8 - Fair Value Measurements under Part II, Item 8, of the Form 10-K for additional information of the definition of fair value and the fair value hierarchy.

In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded losses totaling $1 million in the first nine months of 2011 and losses totaling less than $1 million in the first nine months of 2010 related to valuation adjustments for counterparty default risk. At September 30, 2011, the counterparty default risk valuation adjustment related to net derivative assets totaled less than $1 million for Ameren Missouri and Genco. The counterparty default risk valuation adjustment related to net derivative liabilities totaled less than $1 million and $22 million for Ameren 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 September 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	$	-	$	-	$	37	$	37
	Natural gas		4		-		2		6
	Power		-		7		160		167
	Nuclear Decommissioning Trust Fund ^(c) :
	Cash and cash equivalents		2		-		-		2
	Equity securities:
	U.S. large capitalization		200		-		-		200
	Debt securities:
	Corporate bonds		-		36		-		36
	Municipal bonds		-		2		-		2
	U.S. treasury and agency securities		-		82		-		82
	Asset-backed securities		-		6		-		6
	Other		-		1		-		1
AMO	Derivative assets - commodity contracts ^(b) :
	Heating oil		-		-		23		23
	Power		-		2		23		25
	Nuclear Decommissioning Trust Fund ^(c) :
	Cash and cash equivalents		2		-		-		2
	Equity securities:
	U.S. large capitalization		200		-		-		200
	Debt securities:
	Corporate bonds		-		36		-		36
	Municipal bonds		-		2		-		2
	U.S. treasury and agency securities		-		82		-		82
	Asset-backed securities		-		6		-		6
	Other		-		1		-		1
AIC	Derivative assets - commodity contracts ^(b) :
	Natural gas		-		-		2		2
	Power		-		-		88		88
Genco	Derivative assets - commodity contracts ^(b) :
	Heating oil		-		-		11		11
	Natural gas		1		-		-		1
	Power		-		-		-		-
Liabilities:
Ameren ^(a)	Derivative liabilities - commodity contracts ^(b) :
	Heating oil	$	-	$	-	$	7	$	7
	Natural gas		20		-		130		150
	Power		-		5		46		51
	Uranium		-		-		1		1
AMO	Derivative liabilities - commodity contracts ^(b) :
	Heating oil		-		-		3		3
	Natural gas		9		-		11		20
	Power		-		1		5		6
	Uranium		-		-		1		1
AIC	Derivative liabilities - commodity contracts ^(b) :
	Natural gas		6		-		118		124
	Power		-		-		222		222
Genco	Derivative liabilities - commodity contracts ^(b) :
	Heating oil		-		-		3		3
	Natural gas		1		-		-		1
	Power		-		-		-		-

(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.

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 September 30, 2011:


	Net derivative commodity contracts
Three Months	Ameren			Ameren Missouri			Ameren Illinois			Genco			Other ^(c)
Heating oil:
Beginning balance at July 1, 2011	$	68		$	41		$	(a	)	$	21		$	6
Realized and unrealized gains (losses):
Included in earnings ^(b)		(7	)		-			(a	)		(5	)		(2	)
Included in regulatory assets/liabilities		(12	)		(12	)		(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(19	)		(12	)		(a	)		(5	)		(2	)
Purchases		1			2			(a	)		(1	)		-
Sales		(1	)		(1	)		(a	)		-			-
Settlements		(19	)		(10	)		(a	)		(7	)		(2	)
Ending balance at September 30, 2011	$	30		$	20		$	(a	)	$	8		$	2

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	(22	)	$	(14	)	$	(a	)	$	(6	)	$	(2	)

Natural gas:
Beginning balance at July 1, 2011	$	(117	)	$	(11	)	$	(106	)	$	-		$	-
Realized and unrealized gains (losses):
Included in earnings ^(b)		-			-			-			-			-
Included in regulatory assets/liabilities		(33	)		(2	)		(31	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(33	)		(2	)		(31	)		-			-
Purchases		(1	)		-			(1	)		-			-
Settlements		23			2			22			-			(1	)
Ending balance at September 30, 2011	$	(128	)	$	(11	)	$	(116	)	$	-		$	(1	)

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	(29	)	$	(2	)	$	(27	)	$	-		$	-

Power:
Beginning balance at July 1, 2011	$	117		$	25		$	(204	)	$	1		$	295
Realized and unrealized gains (losses):
Included in earnings ^(b)		-			-			-			-			-
Included in OCI		(7	)		-			-			-			(7	)
Included in regulatory assets/liabilities		25			-			35			(a	)		(10	)
Total realized and unrealized gains (losses)		18			-			35			-			(17	)
Purchases		2			-			-			-			2
Sales		(1	)		-			-			-			(1	)
Settlements		(18	)		(7	)		35			(1	)		(45	)
Transfers into Level 3		(2	)		-			-			-			(2	)
Transfers out of Level 3		(2	)		-			-			-			(2	)
Ending balance at September 30, 2011	$	114		$	18		$	(134	)	$	-		$	230

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	22		$	-		$	26		$	-		$	(4	)

Uranium:
Beginning balance at July 1, 2011	$	(2	)	$	(2	)	$	(a	)	$	(a	)	$	(a	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		-			-			(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		-			-			(a	)		(a	)		(a	)
Settlements		1			1			(a	)		(a	)		(a	)
Ending balance at September 30, 2011	$	(1	)	$	(1	)	$	(a	)	$	(a	)	$	(a	)

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	-		$	-		$	(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.

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 September 30, 2010:


	Net derivative commodity contracts
Three Months	Ameren			Ameren Missouri			Ameren Illinois			Genco			Other ^(c)
Heating oil:
Beginning balance at July 1, 2010	$	29		$	16		$	(a	)	$	10		$	3
Realized and unrealized gains (losses):
Included in earnings ^(b)		4			-			(a	)		4			-
Included in regulatory assets/liabilities		8			8			(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		12			8			(a	)		4			-
Purchases		-			-			(a	)		-			-
Settlements		(3	)		(2	)		(a	)		(2	)		1
Ending balance at September 30, 2010	$	38		$	22		$	(a	)	$	12		$	4

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2010	$	13		$	8		$	(a	)	$	4		$	1

Natural gas:
Beginning balance at July 1, 2010	$	(138	)	$	(15	)	$	(123	)	$	-		$	-
Realized and unrealized gains (losses):
Included in earnings ^(b)		-			-			-			-			-
Included in regulatory assets/liabilities		(70	)		(7	)		(63	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(70	)		(7	)		(63	)		-			-
Purchases		(1	)		-			(1	)		-			-
Settlements		27			4			23			-			-
Ending balance at September 30, 2010	$	(182	)	$	(18	)	$	(164	)	$	-		$	-

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2010	$	(65	)	$	(7	)	$	(58	)	$	-		$	-

Power:
Beginning balance at July 1, 2010	$	54		$	5		$	(406	)	$	3		$	452
Realized and unrealized gains (losses):
Included in earnings ^(b)		20			-			-			-			20
Included in OCI		5			-			-			-			5
Included in regulatory assets/liabilities		(15	)		13			(92	)		(a	)		64
Total realized and unrealized gains (losses)		10			13			(92	)		-			89
Purchases		(2	)		-			2			(6	)		2
Sales		11			1			-			7			3
Settlements		(24	)		(8	)		32			(1	)		(47	)
Transfers into Level 3		-			-			-			-			-
Transfers out of Level 3		(1	)		-			-			-			(1	)
Ending balance at September 30, 2010	$	48		$	11		$	(464	)	$	3		$	498

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2010	$	(10	)	$	10		$	(96	)	$	(2	)	$	78

Uranium:
Beginning balance at July 1, 2010	$	(4	)	$	(4	)	$	(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 September 30, 2010	$	(2	)	$	(2	)	$	(a	)	$	(a	)	$	(a	)

Change in unrealized gains (losses) related to assets/liabilities held at September 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.

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 nine months ended September 30, 2011:


	Net derivative commodity contracts
Nine 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)		10			-			(a	)		7			3
Included in regulatory assets/liabilities		10			10			(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		20			10			(a	)		7			3
Purchases		3			4			(a	)		(1	)		-
Sales		(1	)		(1	)		(a	)		-			-
Settlements		(43	)		(23	)		(a	)		(15	)		(5	)
Ending balance at September 30, 2011	$	30		$	20		$	(a	)	$	8		$	2

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	4		$	2		$	(a	)	$	1		$	1

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		(46	)		(3	)		(43	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(46	)		(3	)		(43	)		-			-
Purchases		-			-			1			-			(1	)
Settlements		66			6			60			-			-
Ending balance at September 30, 2011	$	(128	)	$	(11	)	$	(116	)	$	-		$	(1	)

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	(34	)	$	(3	)	$	(31	)	$	-		$	-

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		(2	)		-			-			-			(2	)
Included in regulatory assets/liabilities		89			6			82			(a	)		1
Total realized and unrealized gains (losses)		69			6			82			(1	)		(18	)
Purchases		61			29			-			-			32
Sales		(17	)		-			-			-			(17	)
Settlements		(34	)		(19	)		136			(2	)		(149	)
Transfers into Level 3		(1	)		(1	)		-			-			-
Transfers out of Level 3		-			1			-			-			(1	)
Ending balance at September 30, 2011	$	114		$	18		$	(134	)	$	-		$	230

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	77		$	1		$	70		$	(1	)	$	7

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	)
Settlements		1			1			(a	)		(a	)		(a	)
Ending balance at September 30, 2011	$	(1	)	$	(1	)	$	(a	)	$	(a	)	$	(a	)

Change in unrealized gains (losses) related to assets/liabilities held at September 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.

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 nine months ended September 30, 2010:


	Net derivative commodity contracts
Nine 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)		(6	)		-			(a	)		(4	)		(2	)
Included in regulatory assets/liabilities		(3	)		(3	)		(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(9	)		(3	)		(a	)		(4	)		(2	)
Purchases		32			18			(a	)		11			3
Settlements		(45	)		(25	)		(a	)		(16	)		(4	)
Ending balance at September 30, 2010	$	38		$	22		$	(a	)	$	12		$	4

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2010	$	(5	)	$	(3	)	$	(a	)	$	(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		(179	)		(21	)		(158	)		(a	)		(a	)
Total realized and unrealized gains (losses)		(179	)		(21	)		(158	)		-			-
Purchases		(5	)		-			(5	)		-			-
Settlements		69			9			60			-			-
Ending balance at September 30, 2010	$	(182	)	$	(18	)	$	(164	)	$	-		$	-

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2010	$	(116	)	$	(14	)	$	(102	)	$	-		$	-

Power:
Beginning balance at January 1, 2010	$	38		$	(1	)	$	(422	)	$	1		$	460
Realized and unrealized gains (losses):
Included in earnings ^(b)		44			-			-			2			42
Included in OCI		11			-			-			-			11
Included in regulatory assets/liabilities		(8	)		26			(161	)		(a	)		127
Total realized and unrealized gains (losses)		47			26			(161	)		2			180
Purchases		36			4			19			(10	)		23
Sales		6			2			-			12			(8	)
Settlements		(53	)		(17	)		100			(2	)		(134	)
Transfers into Level 3		(1	)		-			-			-			(1	)
Transfers out of Level 3		(25	)		(3	)		-			-			(22	)
Ending balance at September 30, 2010	$	48		$	11		$	(464	)	$	3		$	498

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2010	$	6		$	2		$	(138	)	$	1		$	141

Uranium:
Beginning balance at January 1, 2010	$	(2	)	$	(2	)	$	(a	)	$	(a	)	$	(a	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		-			-			(a	)		(a	)		(a	)
Total realized and unrealized gains (losses)		-			-			(a	)		(a	)		(a	)
Ending balance at September 30, 2010	$	(2	)	$	(2	)	$	(a	)	$	(a	)	$	(a	)

Change in unrealized gains (losses) related to assets/liabilities held at September 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.

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 September 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 nine months ended September 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 September 30, 2011, and December 31, 2010:


	September 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)	$	6,860	$	7,732	$	7,008	$	7,661
Preferred stock		142		89		142		102
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	3,955	$	4,493	$	3,954	$	4,281
Preferred stock		80		53		80		62
Ameren Illinois:
Long-term debt (including current portion)	$	1,658	$	1,945	$	1,807	$	2,067
Preferred stock		62		36		62		40
Genco:
Long-term debt (including current portion)	$	824	$	817	$	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 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 September 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 nine months ended September 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									Nine Months
Agreement	Income Statement Line Item		AMO			AIC			Genco			AMO			AIC			Genco
Genco and EEI power supply agreements with Marketing Company	Operating Revenues	2011	$	(a	)	$	(a	)	$	289		$	(a	)	$	(a	)	$	771
		2010		(a	)		(a	)		293			(a	)		(a	)		811
Genco gas sales to Medina Valley	Operating Revenues	2011		(a	)		(a	)		(b	)		(a	)		(a	)		2
		2010		(a	)		(a	)		(b	)		(a	)		(a	)		1
Total Operating Revenues		2011	$	(a	)	$	(a	)	$	289		$	(a	)	$	(a	)	$	773
		2010		(a	)		(a	)		293			(a	)		(a	)		812
Ameren Illinois power supply agreements with Marketing Company	Purchased power	2011	$	(a	)	$	66		$	(a	)	$	(a	)	$	160		$	(a	)
		2010		(a	)		44			(a	)		(a	)		177			(a	)
EEI power supply agreement with Marketing Company	Purchased power	2011		(a	)		(a	)		24			(a	)		(a	)		36
		2010		(a	)		(a	)		7			(a	)		(a	)		11
Total Purchased Power		2011	$	(a	)	$	66		$	24		$	(a	)	$	160		$	36
		2010		(a	)		44			7			(a	)		177			11
Ameren Services support services agreement	Other operations and maintenance	2011	$	27		$	20		$	4		$	86		$	68		$	14
		2010		29			24			6			97			77			19
AFS support services agreement	Other operations and maintenance	2011		(a	)		(a	)		(a	)		(a	)		(a	)		(a	)
		2010		2			(b	)		1			5			(b	)		2
Insurance premiums ^(c)	Other operations and maintenance	2011		(b	)		(a	)		-			(b	)		(a	)		-
		2010		(b	)		(a	)		-			1			(a	)		-
Total Other Operations and Maintenance Expenses		2011	$	27		$	20		$	4		$	86		$	68		$	14
		2010		31			24			7			103			77			21
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.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

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

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

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at September 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, nuclear fuel, and methane gas. We also have entered into various long-term commitments for purchased power and natural gas for distribution. The table below presents our estimated fuel, purchased power, and other commitments at September 30, 2011. Ameren’s and Ameren Missouri’s coal commitments include multi-year agreements to procure ultra-low sulfur coal and related transportation from the Powder River Basin in Wyoming. Ameren’s and Ameren Missouri’s purchased power obligations include a 102-MW power purchase agreement with a wind farm operator that expires in 2024. Ameren’s and Ameren Illinois’ purchased power obligations include the Ameren Illinois power purchase agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, meter reading services, and an Ameren tax credit obligation at September 30, 2011.


	Coal		Natural Gas		Nuclear		Purchased Power		Methane Gas		Other		Total
Ameren: ^(a)
2011	$	215	$	121	$	50	$	61	$	-	$	138	$	585
2012		1,134		417		36		196		1		169		1,953
2013		785		304		38		310		3		79		1,519
2014		698		224		114		125		3		79		1,243
2015		691		118		74		51		3		52		989
Thereafter		1,653		186		397		798		98		262		3,394
Total	$	5,176	$	1,370	$	709	$	1,541	$	108	$	779	$	9,683
Ameren Missouri:
2011	$	106	$	17	$	50	$	6	$	-	$	83	$	262
2012		618		65		36		19		1		70		809
2013		609		47		38		19		3		48		764
2014		630		34		114		19		3		47		847
2015		620		20		74		19		3		28		764
Thereafter		1,589		39		397		175		98		160		2,458
Total	$	4,172	$	222	$	709	$	257	$	108	$	436	$	5,904
Ameren Illinois:
2011	$	-	$	99	$	-	$	55	$	-	$	11	$	165
2012		-		342		-		177		-		21		540
2013		-		255		-		290		-		22		567
2014		-		186		-		106		-		22		314
2015		-		96		-		32		-		24		152
Thereafter		-		146		-		624		-		102		872
Total	$	-	$	1,124	$	-	$	1,284	$	-	$	202	$	2,610
Genco:
2011	$	78	$	3	$	-	$	-	$	-	$	40	$	121
2012		376		6		-		-		-		54		436
2013		96		3		-		-		-		8		107
2014		41		3		-		-		-		8		52
2015		42		2		-		-		-		-		44
Thereafter		-		-		-		-		-		-		-
Total	$	633	$	17	$	-	$	-	$	-	$	110	$	760

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

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 plants. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards for SO ₂ and NO ₂ emissions; the CSAPR, which will require further reduction of SO ₂ 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, SO ₂ 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. The EPA also plans to propose an additional rule governing NSPS and emission guidelines for greenhouse gas emissions applicable to new and existing electric generating units. These new regulations may be litigated, 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 SO ₂ and NO _x emissions as of September 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 a variety of factors including:

•

additional federal or state requirements;

•

regulation of greenhouse gas emissions;

•

new national ambient air quality standards or changes to existing standards for ozone, fine particulates, SO ₂ , and NO _x emissions;

•

the final requirements under a MACT standard for the control of mercury and other hazardous air pollutants;

•

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; and

•

alternative compliance strategies.

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 and the estimates provided in the Form 10-Q for the period ended June 30, 2011. On October 4, 2011, Resources Company announced that Genco’s Meredosia and Hutsonville energy centers will cease operating at the end of 2011. The closure of those two energy centers has allowed the Merchant Generation segment additional flexibility in the methods to achieve compliance with environmental standards.


	2011		2012 - 2015					2016 - 2020					Total
AMO ^(a)	$	40	$	315	-	$	390	$	905	-	$	1,105	$	1,260	-	$	1,535
Genco		90		385	-		470		50	-		60		525	-		620
AERG		10		90	-		110		15	-		20		115	-		140
Ameren	$	140	$	790	-	$	970	$	970	-	$	1,185	$	1,900	-	$	2,295

(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 SO ₂ and NO _x emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO ₂ 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 SO ₂ emissions, annual NO _x emissions, and ozone season NO _x emissions. The cap-and-trade program for both annual and ozone season NO _x emissions went into effect on January 1, 2009. The SO ₂ emissions cap-and-trade program 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 SO ₂ and annual NO _x reductions and on May 1, 2012, for ozone season NO _x reductions, 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 27 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 SO ₂ 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 SO ₂ , annual NO _x , or ozone season NO _x program. Multiple legal challenges have been filed requesting a stay of enforcement of the rule or to have CSAPR partially or entirely vacated. The CSAPR is voluminous and complex and our review of the finalized regulation and its impacts is ongoing. In October 2011, Genco announced that its Meredosia and Hutsonville energy centers will cease operating at the end of 2011 primarily due to the expected cost of complying with CSAPR. As a result, in September 2011, Ameren and Genco each recorded an asset impairment charge to remove its remaining net investment in the Hutsonville and Meredosia energy centers. See Note 1 - Summary of Significant Accounting Policies for additional information.

Separately, in January and June 2010, the EPA finalized new ambient air quality standards for SO ₂ and NO ₂ 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 September 2011, the EPA withdrew its draft annual national ambient air quality standard for ozone and announced that it was implementing the 2008 national ambient air quality standard for ozone. The EPA is required to revisit this standard again in 2013.

In March 2011, the EPA issued proposed rules under the Clean Air Act that establish a MACT standard to control mercury emissions and other hazardous air pollutants, such as acid gases, metals, and particulate matter. The MACT standard sets emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. The EPA estimates that the new rule would result in a 91% reduction in mercury emissions from 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, SO ₂ and NO _x. The proposed rules are scheduled to be finalized in December 2011. Compliance is expected to be required no later than 2016 and potentially as early as late 2014. The proposed MACT rule is voluminous and complex, and the final rules may 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 whether 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 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 SO ₂ 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 additional emission reductions requirements in 2014 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 whether the EPA’s proposed MACT standard, when finalized, 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, SO ₂ , and NO _x emissions by 2015. To comply with the MPS, Genco and AERG are installing equipment designed to reduce mercury, NO _x , and SO ₂ emissions. Genco and AERG have installed a total of three scrubbers at two energy centers and 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 at AERG’s E.D. Edwards energy center. Genco’s compliance plan includes the closure of the Meredosia and Hutsonville energy centers at the end of December 2011. Genco and AERG expect to install additional, or optimize existing, pollution control equipment to meet new and incremental 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 SO ₂ , annual NO _x , or ozone season NO _x programs. See Note 1 - Summary of Significant Accounting Policies for the SO ₂ and NO _x emission allowance book values that were classified as intangible assets as of September 30, 2011, and the impairment recorded during the second quarter of 2011.

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 SO ₂ emissions and the NO _x budget trading program for both the annual and ozone season NO _x allowances. The CSAPR, which replaces CAIR, 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 SO ₂ allowances may be used solely for achieving compliance with the acid rain program’s SO ₂ emission limitations. Consequently, Ameren, Ameren Missouri and Genco do not expect to use all of their existing SO ₂ allowances issued under the acid rain program for their operations. Any unused annual and ozone season NO _x allowances issued under CAIR cannot be used for compliance with CSAPR. In October 2011, the EPA proposed some modifications to the final CSAPR that could eliminate the restrictions on interstate emission allowance trading in 2012 and 2013. Ameren, Ameren Missouri and Genco are analyzing the CSAPR’s SO ₂ and NO _x emission allowance allocations and trading restrictions. In October 2011, the EPA transferred to Ameren, Ameren Missouri and Genco control of their allotment of CSAPR emission allowances for 2012 and 2013.

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 _. Additionally, Ameren, Ameren Missouri and Genco expect their 2012 allotment of both annual and ozone season NO _x will approximate their emission levels, based on changes in plant operations. Ameren, Ameren Missouri and Genco are studying their compliance options to identify additional opportunities that may exist for compliance in an economical fashion. 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 to achieve compliance with the CSAPR in future phase-in years.

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 CO ₂ 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 CO ₂ . Ameren’s analysis showed 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 CO ₂ 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 CO ₂ , 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 CO ₂ equivalents, such projects could trigger permitting requirements under the NSR/Prevention of Significant Deterioration program and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources also would be required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. Separately, in December 2010, the EPA announced a settlement agreement under which it would issue NSPS for greenhouse gas emissions at new and existing fossil fuel-fired power plants by July 26, 2011. The EPA has missed its deadline, and an extension of that deadline, to issue its proposed standard for power plants, called the performance standard and has not specified a new estimate of when it will issue that proposal. The settlement agreement requires a final rule by May 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 consider 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 in State of Connecticut v. American Electric Power rejected state efforts to impose liability for CO ₂ 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 named Comer v. Murphy Oil (Comer), where a Mississippi property owner sued several industrial companies, including Ameren Missouri and Genco, alleging that CO ₂ 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.

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, nuclear, and combined cycle 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 September 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.

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


	Estimate
	Low		High		Recorded Liability ^(a)
Ameren	$	112	$	191	$	112
Ameren Missouri		3		4		3
Ameren Illinois		109		187		109

(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 September 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 September 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 is currently performing a site investigation. As of September 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 September 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 2012. 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 September 30, 2011, Ameren Missouri estimated its obligation at $0.3 million to $10 million. Ameren Missouri has a liability of $0.3 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 September 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. 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 September 30, 2011. As of September 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 September 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 would 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 each recorded, 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.

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 221 parties named in some pending cases and as few as two in others. However, in the cases that were pending as of September 30, 2011, the average number of parties was 79.

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 September 30, 2011:


Ameren	Ameren Missouri	Ameren Illinois	Genco	Total ^(a)
5	64	81	(b)	107

(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 September 30, 2011, six asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

At September 30, 2011, Ameren, Ameren Missouri, Ameren Illinois and Genco had liabilities of $20 million, $8 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 September 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

In Exelon Corporation v. Department of Revenue , the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear the case, and the case became final. During the second quarter of 2010, Genco and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. On November 2, 2011, EEI received a notice of proposed tax liability, documenting the State of Illinois’ position that EEI did not qualify for the manufacturing exemption it utilized during 2010. Genco is reviewing, and will respond to, the proposed tax liability notice. Ameren and Genco do not believe that it is probable that Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. From the second quarter of 2010 through September 30, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $23 million and $16 million, respectively.

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

NOTE 10 - CALLAWAY ENERGY CENTER

Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear power plants. Under the NWPA, Ameren and other utilities who own and operated those plants are responsible for paying the disposal costs. The NWPA established the fee that these utilities pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatt hour generated by those plants and sold. The NWPA also requires the DOE annually review the nuclear waste fee against the cost of the nuclear waste disposal program and to propose to the United States Congress any fee adjustment as necessary to offset the costs of the program. As required by the NWPA, Ameren and other utilities have entered into standard contracts with the federal government, which was represented by the DOE, implementing these provisions of the NWPA. Consistent with the NWPA and its contract, Ameren Missouri collects one mill from its electric customers for each kilowatt hour of electricity that it generates and sells from its Callaway energy center.

Although the NWPA and the standard contract provide that the federal government would begin to dispose of spent nuclear fuel by 1998, the federal government acknowledged since at least 1994 that it would not meet that date. The federal government is not currently predicting when it will begin to meet its disposal obligation. Ameren Missouri has sufficient installed capacity at the Callaway energy center to store the spent nuclear fuel generated at Callaway through 2020 and has the capability for additional storage capacity for spent nuclear fuel generated through the end of the energy center’s licensed life.

Until January 2009, the DOE program provided for spent nuclear fuel disposal to take place at a geologic repository to be constructed at Yucca Mountain, Nevada. Beginning in January 2009, the Obama administration announced that a repository at Yucca Mountain was unworkable and has taken steps to terminate the Yucca Mountain program, while acknowledging the federal government’s continuing obligation to dispose of utilities’ spent nuclear fuel. The DOE has established an advisory commission to make recommendations for the storage and disposal of utilities’ spent nuclear fuel. The commission’s final recommendations are scheduled to be issued in January 2012.

In view of the federal government’s efforts to terminate the Yucca Mountain program, the Nuclear Energy Institute, a number of individual utilities, and the National Association of Regulatory Utility Commissioners sued the DOE in the United States Court of Appeals for the District of Columbia Circuit seeking the suspension of the one mill nuclear waste fee in view of the DOE’s failure to undertake an appropriate fee adequacy review that reflects the current state of the nuclear waste program. That case is pending. The delay in DOE carrying out its obligation to dispose of spent nuclear fuel from the Callaway energy center is not expected to adversely affect the continued operation of the 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 June 2011, the parties reached a settlement that included a 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 “Operating Expenses - Depreciation and amortization” and “Operating Expenses - Other operations and maintenance” expense line items, respectively, on its statement of income for the nine months ended September 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 was dismissed in July 2011.

In December 2011, 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 current 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 may be adjusted at such times to reflect changed estimates. This cost study was filed with the MoPSC in September 2011. Based on the results of this updated cost study and associated financial analysis, Ameren Missouri recommended to the MoPSC that the current rate of deposits to the trust fund continue to be appropriate and do not need to be changed. 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 nine months ended September 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 nine months ended September 30, 2011 and 2010.


	Three Months						Nine Months
	2011			2010			2011			2010
Ameren: ^(a)
Net income (loss)	$	287		$	(164	)	$	500		$	97
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(2), $9, $(6), and $20, respectively		(2	)		14			(8	)		31
Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $1, $8, $(1), and $20, respectively		(1	)		(14	)		2			(34	)
Pension and other postretirement activity, net of income taxes (benefit) of $-, $- $(2), and $6, respectively		(1	)		-			(2	)		6
Total comprehensive income (loss), net of taxes	$	283		$	(164	)	$	492		$	100
Less: Net income attributable to noncontrolling interests, net of taxes		2			3			6			10
Total comprehensive income (loss) attributable to Ameren Corporation, net of taxes	$	281		$	(167	)	$	486		$	90
Ameren Illinois:
Net income	$	98		$	110		$	170		$	215
Pension and other postretirement activity, net of income taxes (benefit) of $(1), $(1), $(2), and $(1), respectively		(1	)		(1	)		(3	)		(2	)
Total comprehensive income, net of taxes	$	97		$	109		$	167		$	213
Genco:
Net income (loss)	$	(4	)	$	(100	)	$	31		$	(62	)
Pension and other postretirement activity, net of income taxes (benefit) of $-, $-, $1, and $5, respectively		1			-			2			4
Total comprehensive income (loss), net of taxes	$	(3	)	$	(100	)	$	33		$	(58	)
Less: Net income attributable to noncontrolling interest, net of taxes		1			1			2			3
Total comprehensive income (loss) attributable to Genco	$	(4	)	$	(101	)	$	31		$	(61	)

(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 September 30, 2011, and its pension funding policy, Ameren expects to make annual contributions of $125 million to $150 million in each of the next five years, with aggregate estimated contributions of $690 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. In August 2011, Ameren Illinois contributed to Ameren’s postretirement benefit VEBA trust an incremental $100 million in excess of Ameren Illinois’ annual postretirement net periodic cost for regulatory purposes. This cash contribution will reduce future postretirement net periodic cost to the extent expected returns are achieved on the contribution.

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


	Pension Benefits ^(a)												Postretirement Benefits ^(a)
	Three Months						Nine Months						Three Months						Nine Months
	2011			2010			2011			2010			2011			2010			2011			2010
Service cost	$	19		$	18		$	57		$	51		$	6		$	5		$	17		$	15
Interest cost		45			45			135			138			15			16			44			46
Expected return on plan assets		(54	)		(53	)		(162	)		(159	)		(14	)		(14	)		(41	)		(42	)
Amortization of:
Transition obligation		-			-			-			-			1			1			2			2
Prior service cost (benefit)		-			1			(1	)		5			(2	)		(2	)		(6	)		(6	)
Actuarial loss		10			5			31			14			1			-			3			1
Net periodic cost	$	20		$	16		$	60		$	49		$	7		$	6		$	19		$	16

(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 nine months ended September 30, 2011, and 2010:


	Pension Costs								Postretirement Costs
	Three Months				Nine Months				Three Months				Nine Months
	2011		2010		2011		2010		2011		2010		2011		2010
Ameren Missouri	$	13	$	10	$	39	$	31	$	3	$	3	$	8	$	8
Ameren Illinois		4		3		12		9		3		2		9		6
Genco		1		1		6		6		1		-		2		1
Other		2		2		3		3		-		1		-		1
Ameren ^(a)	$	20	$	16	$	60	$	49	$	7	$	6	$	19	$	16

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

NOTE 13 - SEGMENT INFORMATION

Ameren has three reportable segments: Ameren Missouri, the Ameren Illinois Regulated Segment, 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 regulated 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 nine months ended September 30, 2011, and 2010, and total assets as of September 30, 2011, and December 31, 2010.


Three Months	Ameren Missouri		Ameren Illinois Regulated		Merchant Generation			Other			Intersegment Eliminations			Consolidated
2011:
External revenues	$	1,109	$	742	$	415		$	2		$	-		$	2,268
Intersegment revenues		6		3		67			2			(78	)		-
Net income (loss) attributable to Ameren Corporation ^(a)		190		98		(9	)		6			-			285
2010:
External revenues	$	1,053	$	743	$	470		$	1		$	-		$	2,267
Intersegment revenues		7		3		44			4			(58	)		-
Net income (loss) attributable to Ameren Corporation ^(a)		223		90		(470	)		(10	)		-			(167	)
Nine Months
2011:
External revenues	$	2,690	$	2,166	$	1,094		$	3		$	-		$	5,953
Intersegment revenues		19		10		163			3			(195	)		-
Net income (loss) attributable to Ameren Corporation ^(a)		301		168		26			(1	)		-			494
2010:
External revenues	$	2,486	$	2,296	$	1,149		$	1		$	-		$	5,932
Intersegment revenues		17		8		178			10			(213	)		-
Net income (loss) attributable to Ameren Corporation ^(a)		363		171		(428	)		(19	)		-			87
As of September 30, 2011:
Total assets	$	12,638	$	7,064	$	3,794		$	1,209		$	(1,349	)	$	23,356
As of December 31, 2010:
Total assets	$	12,504	$	7,406	$	3,934		$	1,354		$	(1,683	)	$	23,515

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

NOTE 14 - DISCONTINUED OPERATIONS

On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the 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 nine months ended September 30, 2010:


	2010
	Three Months		Nine Months
Operating revenues	$	98	$	274
Operating expenses		67		201
Operating income		31		73
Other income		-		1
Interest charges		4		14
Income taxes		8		20
Income from discontinued operations, net of tax	$	19	$	40

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 reported net income of $285 million for the third quarter of 2011, compared with a net loss of $167 million for the third quarter of 2010. Ameren also reported net income of $494 million for the nine months ended September 30, 2011, compared with net income of $87 million for the nine months ended September 30, 2010. Asset impairment and other charges lowered after-tax earnings by $76 million and $77 million in the third quarter of 2011 and the first nine months of 2011, respectively. These charges resulted principally from the MoPSC’s disallowance of the recovery of costs of enhancements relating to the rebuilding of Ameren Missouri’s Taum Sauk energy center and the planned closure of Genco’s Meredosia and Hutsonville energy centers at the end of 2011. Noncash goodwill and other asset impairment charges reduced after-tax earnings by $522 million in the third quarter and first nine months of 2010. Ameren’s earnings in the third quarter of 2011 and the first nine months of 2011 were positively impacted, compared with the year-ago periods, by the Ameren Missouri and Ameren Illinois electric rate increases and lower interest expense. These positive factors were offset, in part, by reduced margins in the Merchant Generation segment due to lower realized power prices, higher fuel and transportation-related expenses and unrealized net losses on MTM activity related to nonqualifying power hedges and fuel-related contracts. Also impacting earnings in the first nine months of 2011 were reduced rate-regulated retail sales volumes, increased storm-related expenses and lower capitalized financing expenses.

In early October 2011, Resources Company announced that it will cease operating Genco’s Meredosia and Hutsonville energy centers by the end of 2011. These two older energy centers make up a small portion of Ameren’s Merchant Generation fleet, providing approximately 4% of the Merchant Generation’s total generation over the last two years. These closures are primarily the result of complying with the CSAPR. The CSAPR tightens SO ₂ and NOx emission limits to the point that continued operation of these energy centers is not economical. Closure of the Meredosia and Hutsonville energy centers will reduce the Merchant Generation segment’s fleet emission levels. As a result, the Merchant Generation environmental compliance plan no longer includes the use of dry sorbent injection at its E.D. Edwards energy center to comply with the CSAPR or MPS. The closure of these two energy centers has allowed the Merchant Generation segment additional flexibility in the methods to achieve compliance with environmental standards. As a result, the Merchant Generation segment has further reduced its expected 2011 through 2015 capital expenditures by approximately $70 million compared to those estimates disclosed in the Form 10-Q for the quarter ended June 30, 2011.

On October 21, 2011, Ameren announced a voluntary separation offer to approximately 715 management and union employees of Ameren Missouri and Ameren Services. Those accepting the offer are to leave Ameren by the end of 2011. The voluntary separation offer is part of Ameren Missouri’s efforts to align its spending with regulatory outcomes and economic conditions and to improve its earned returns. Ameren Missouri will continue to explore options to reduced regulatory lag and enhance its cash flows and earned returns, and thereby facilitate more timely investments in its energy infrastructure.

Also in October 2011, the Energy Infrastructure Modernization Act was enacted into law in Illinois. The Illinois General Assembly also passed House Bill 3036, which, if enacted, would result in certain amendments to the Energy Infrastructure Modernization Act. The Energy Infrastructure Modernization Act will provide more predictable formulaic ratemaking for Ameren Illinois’ electric distribution business. Rates would be set annually based on its prudently incurred actual costs. The allowed return on equity would be based on the annual average of 30-year United States treasury bonds plus 600 basis points under the Energy Infrastructure Modernization Act or 580 basis points under House Bill 3036. The law requires utilities that opt-in to achieve stringent performance standards and provides return on equity penalties if these standards are not met. Ameren Illinois would be required to invest $625 million in capital expenditures incremental to Ameren Illinois’ average capital expenditures for calendar years 2008 through 2010 over the next ten years to modernize its distribution system. Such investments are expected to encourage economic development and would create an estimated 450 additional jobs within Illinois. The law also provides for oversight by the ICC to ensure that investments made and costs incurred are prudent. To become law, House Bill 3036 must be approved by the Illinois Governor, or if the Illinois Governor elects to veto the legislation, the Illinois General Assembly would have to override the veto. Ameren Illinois plans to withdraw its pending electric delivery rate case and is developing plans for filing for performance-based formula electric delivery rates under the Energy Infrastructure Modernization Act. However, Ameren Illinois’ pending natural gas delivery rate case will continue to move forward since this law does not apply to natural gas utilities.

Ameren’s goal is to seek and obtain constructive regulatory frameworks that allow its rate-regulated utilities to recover costs in a timely fashion and that provide a reasonable opportunity to earn a fair return on investments. The voluntary separation offer discussed above and Ameren’s continued disciplined cost management across all of its business segments are evidence of Ameren’s ongoing plan to align overall spending to regulatory outcomes and economic conditions. Ameren believes these efforts, along with its plans for growing investments in FERC-regulated electric transmission projects, will lead to further improvement in the returns Ameren earns on its regulated investments. Further, Ameren’s disciplined focus on managing both operating and capital costs at its Merchant Generation segment is designed to ensure that this business is well-positioned to benefit from an expected improvement in power prices.

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.

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

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

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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.

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

Ameren earned net income attributable to Ameren Corporation of $285 million, or $1.18 per share, in the third quarter of 2011, compared with a net loss of $167 million, or 70 cents per share, in the third quarter of 2010. Net loss attributable to Ameren Corporation in the third quarter of 2011 in the Merchant Generation segment was $9 million, compared to a $470 million net loss in the third quarter of 2010. Net income attributable to Ameren Corporation in the third quarter of 2011 increased in the Ameren Illinois Regulated Segment by $8 million from the prior-year period. Net income attributable to Ameren Corporation in the third quarter of 2011 decreased in the Ameren Missouri segment by $33 million from the prior-year period.

Net income attributable to Ameren Corporation increased to $494 million, or $2.05 per share, in the first nine months of 2011 from $87 million, or 37 cents per share, in the first nine months of 2010. In the first nine months of 2011, the Merchant Generation segment reported net income of $26 million, compared to a $428 million net loss in the prior-year period. Net income attributable to Ameren Corporation in the first nine months of 2011 declined in the Ameren Missouri segment and the Ameren Illinois Regulated Segment by $62 million and $3 million, respectively, from the prior-year period.

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

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reduced goodwill, impairment and other charges at the Merchant Generation segment ($2.10 per share in each period);

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higher Ameren Missouri electric rates pursuant to orders issued by the MoPSC, which became effective in June 2010 and in late July 2011, as well as higher Ameren Missouri natural gas rates pursuant to an MoPSC order, which became effective in late February 2011. 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 orders (8 cents per share and 12 cents per share, respectively). These amounts exclude the unfavorable impact of the charge to earnings related to the MoPSC’s disallowance of Taum Sauk rebuild costs discussed below;

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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, Ameren Illinois’ redemptions of $150 million of senior secured notes and $40 million of first mortgage bonds in June 2011 and September 2010, respectively, and a reduction in borrowings under credit facility agreements (4 cents per share and 10 cents per share, respectively);

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a reduction in costs at our energy centers primarily as the result of the timing of scheduled nuclear refueling and maintenance outages at the Callaway energy center (1 cent per share and 10 cents per share, respectively); and

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higher Ameren Illinois electric rates pursuant to orders issued by the ICC in 2010 (2 cents per share and 5 cents per share).

Earnings were unfavorably impacted in the third quarter and first nine months of 2011, compared with the same periods in 2010, by:

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a charge to earnings related to the MoPSC’s July 2011 disallowance of costs of enhancements relating to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance (23 cents per share in each period);

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unrealized net losses on MTM activity primarily related to nonqualifying power hedges and fuel-related contracts as well as unfavorable changes in the market value of investments used to support Ameren’s deferred compensation plans (16 cents per share and 14 cents per share, respectively);

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lower realized electric margins in the Merchant Generation segment, largely due to lower realized revenue per megawatthour sold and higher fuel and related transportation costs (5 cents per share and 14 cents per share, respectively). This amount excludes the unfavorable impacts of net unrealized MTM activity discussed above. See Outlook for expected trends in future coal, transportation and power prices; 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 (1 cent per share and 6 cents per share, respectively).

In addition to the above items affecting both periods, earnings were unfavorably impacted in the first nine months of 2011, compared with the same period in 2010, by

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

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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 items (6 cents per share);

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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, of this report for additional information (5 cents per share); and

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the impact of weather conditions on electric and natural gas demand (estimated at 5 cents per share);

In addition to the above items affecting both periods, earnings were favorably impacted in the first nine 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 third quarter and first nine months of 2010, respectively. For further details regarding the Ameren Companies’ results of operations for the third quarter and first nine months of 2011, including explanations of Margins, Other Operations and Maintenance, Goodwill, Impairment and Other Charges, 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 nine months ended September 30, 2011, and 2010:


	Three Months						Nine Months
	2011			2010			2011			2010
Net income (loss):
Ameren Missouri	$	190		$	223		$	301		$	363
Ameren Illinois		98			109			168			211
Genco		(5	)		(101	)		29			(65	)
Other ^(a)		2			(398	)		(4	)		(422	)
Net income (loss) attributable to Ameren Corporation	$	285		$	(167	)	$	494		$	87

(a)

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

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


	Ameren Missouri			Ameren Illinois Regulated Segment			Merchant Generation			Other / Intersegment Eliminations			Total
Three Months 2011:
Electric margin	$	815		$	361		$	166		$	(3	)	$	1,339
Natural gas margin		12			71			-			1			84
Other revenues		-			-			1			(1	)		-
Other operations and maintenance expenses		(218	)		(152	)		(72	)		10			(432	)
Goodwill, impairment and other charges		(89	)		-			(36	)		1			(124	)
Depreciation and amortization expenses		(102	)		(55	)		(36	)		(3	)		(196	)
Taxes other than income taxes		(85	)		(29	)		(6	)		(1	)		(121	)
Other income and (expenses)		14			-			-			(1	)		13
Interest charges		(54	)		(33	)		(27	)		1			(113	)
Income (taxes) benefit		(102	)		(65	)		1			3			(163	)
Net income (loss)		191			98			(9	)		7			287
Noncontrolling interest and preferred dividends		(1	)		-			-			(1	)		(2	)
Net income (loss) attributable to Ameren Corporation	$	190		$	98		$	(9	)	$	6		$	285
Three Months 2010:
Electric margin	$	787		$	346		$	235		$	(5	)	$	1,363
Natural gas margin		12			72			-			(1	)		83
Other revenues		-			-			-			-			-
Other operations and maintenance expenses		(233	)		(155	)		(72	)		5			(455	)
Goodwill, impairment and other charges		-			-			(589	)		-			(589	)
Depreciation and amortization expenses		(99	)		(52	)		(37	)		(6	)		(194	)
Taxes other than income taxes		(82	)		(29	)		(5	)		(3	)		(119	)
Other income and (expenses)		15			-			-			(1	)		14
Interest charges		(56	)		(37	)		(34	)		(3	)		(130	)
Income (taxes) benefit		(120	)		(54	)		33			4			(137	)
Net income (loss)		224			91			(469	)		(10	)		(164	)
Noncontrolling interest and preferred dividends		(1	)		(1	)		(1	)		-			(3	)
Net income (loss) attributable to Ameren Corporation	$	223		$	90		$	(470	)	$	(10	)	$	(167	)
Nine Months 2011:
Electric margin	$	1,829		$	879		$	509		$	(8	)	$	3,209
Natural gas margin		58			261			-			(1	)		318
Other revenues		4			1			3			(8	)		-
Other operations and maintenance expenses		(682	)		(501	)		(217	)		32			(1,368	)
Goodwill, impairment and other charges		(89	)		-			(38	)		1			(126	)
Depreciation and amortization expenses		(300	)		(161	)		(109	)		(15	)		(585	)
Taxes other than income taxes		(234	)		(96	)		(19	)		(6	)		(355	)
Other income and (expenses)		37			1			-			(2	)		36
Interest charges		(153	)		(103	)		(80	)		-			(336	)
Income (taxes) benefit		(166	)		(111	)		(22	)		6			(293	)
Net income (loss)		304			170			27			(1	)		500
Noncontrolling interest and preferred dividends		(3	)		(2	)		(1	)		-			(6	)
Net income (loss) attributable to Ameren Corporation	$	301		$	168		$	26		$	(1	)	$	494
Nine Months 2010:
Electric margin	$	1,809		$	848		$	610		$	(15	)	$	3,252
Natural gas margin		54			273			-			(2	)		325
Other revenues		1			-			-			(1	)		-
Other operations and maintenance expenses		(691	)		(476	)		(214	)		24			(1,357	)
Goodwill, impairment and other charges		-			-			(589	)		-			(589	)
Depreciation and amortization expenses		(283	)		(158	)		(110	)		(20	)		(571	)
Taxes other than income taxes		(218	)		(95	)		(20	)		(9	)		(342	)
Other income and (expenses)		53			-			1			(3	)		51
Interest charges		(158	)		(108	)		(103	)		(8	)		(377	)
Income (taxes) benefit		(200	)		(109	)		-			14			(295	)
Net income (loss)		367			175			(425	)		(20	)		97
Noncontrolling interest and preferred dividends		(4	)		(4	)		(3	)		1			(10	)
Net income (loss) attributable to Ameren Corporation	$	363		$	171		$	(428	)	$	(19	)	$	87

Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and natural gas margins in the three and nine months ended September 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			Ameren Missouri			Ameren Illinois Regulated			Genco			Other ^(a)
Electric revenue change:
Effect of weather (estimate) ⁽ ^b)	$	8		$	8		$	-		$	-		$	-
Regulated rates:
Higher base rates		44			36			8			-			-
Recovery of FAC under-recovery		26			26			-			-			-
Off-system revenues		5			5			-			-			-
Transmission services		-			-			(1	)		-			1
Illinois pass-through power supply costs		(38	)		-			(16	)		-			(22	)
Energy efficiency programs and environmental remediation cost riders		2			-			2			-			-
Bad debt rider		(6	)		-			(6	)		-			-
Rate-regulated sales (excluding the impact of abnormal weather)		(6	)		(8	)		2			-			-
Wholesale revenues		(5	)		(5	)		-			-			-
Merchant Generation sales price changes, including hedge effect		(39	)		-			-			(27	)		(12	)
Net unrealized MTM losses		(27	)		-			-			(1	)		(26	)
Non-rate-regulated sales and other		41			(3	)		10			20			14
Total electric revenue change	$	5		$	59		$	(1	)	$	(8	)	$	(45	)
Fuel and purchased power change:
Fuel:
Production volume and other	$	(15	)	$	(14	)	$	-		$	(1	)	$	-
FAC under-recovery ^(c)		(4	)		(4	)		-			-			-
Recovery of FAC under-recovery		(26	)		(26	)		-			-			-
Net unrealized MTM losses		(20	)		-			-			(16	)		(4	)
Price - Merchant Generation		(8	)		-			-			(6	)		(2	)
Purchased power		6			13			-			5			(12	)
Illinois pass-through power supply costs		38			-			16			-			22
Total fuel and purchased power change	$	(29	)	$	(31	)	$	16		$	(18	)	$	4
Net change in electric margins	$	(24	)	$	28		$	15		$	(26	)	$	(41	)
Natural gas margins change:
Effect of weather (estimate) ^(b)	$	1		$	-		$	1		$	-		$	-
Bad debt rider		(5	)		-			(5	)		-			-
Change in base rates		3			1			2			-			-
Energy efficiency programs and environmental remediation cost riders		2			-			2			-			-
Sales (excluding impact of abnormal weather) and other		-			(1	)		(1	)		-			2
Net change in natural gas margins	$	1		$	-		$	(1	)	$	-		$	2
Nine months
Electric revenue change:
Effect of weather (estimate) ⁽ ^b)	$	(19	)	$	(14	)	$	(5	)	$	-		$	-
Regulated rates:
Higher base rates		156			138			18			-			-
Recovery of FAC under-recovery		97			97			-			-			-
Off-system revenues		66			66			-			-			-
FAC prudence review disallowance		(17	)		(17	)		-			-			-
Transmission services		22			4			16			-			2
Illinois pass-through power supply costs		(90	)		-			(105	)		-			15
Energy efficiency programs and environmental remediation cost riders		14			-			14			-			-
Bad debt rider		(12	)		-			(12	)		-			-
Rate-regulated sales (excluding impact of abnormal weather)		(40	)		(32	)		(8	)		-			-
Wholesale revenues		(37	)		(37	)		-			-			-
Merchant Generation sales price changes, including hedge effect		(40	)		-			-			(36	)		(4	)
Net unrealized MTM losses		(39	)		(1	)		-			(4	)		(34	)
Non-rate-regulated sales and other		21			4			8			(9	)		18
Total electric revenue change	$	82		$	208		$	(74	)	$	(49	)	$	(3	)


Nine months	Ameren			Ameren Missouri			Ameren Illinois Regulated			Genco			Other ^(a)
Fuel and purchased power change:
Fuel:
Production volume and other	$	(2	)	$	(32	)	$	-		$	20		$	10
FAC under-recovery ^(c)		(112	)		(112	)		-			-			-
Recovery of FAC under-recovery		(97	)		(97	)		-			-			-
Net unrealized MTM losses		(3	)		-			-			(3	)		-
Price - Merchant Generation		(30	)		-			-			(22	)		(8	)
Purchased power		29			53			-			7			(31	)
Illinois pass-through power supply costs		90			-			105			-			(15	)
Total fuel and purchased power change	$	(125	)	$	(188	)	$	105		$	2		$	(44	)
Net change in electric margins	$	(43	)	$	20		$	31		$	(47	)	$	(47	)
Natural gas margins change:
Effect of weather (estimate)	$	1		$	-		$	1		$	-		$	-
Bad debt rider		(10	)		-			(10	)		-			-
Change in base rates		5			3			2			-			-
Energy efficiency programs and environmental remediation cost riders		1			-			1			-			-
Sales (excluding impact of abnormal weather) and other		(4	)		1			(6	)		-			1
Net change in natural gas margins	$	(7	)	$	4		$	(12	)	$	-		$	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 decreased by $24 million, or 2%, and $43 million, or 1%, for the three and nine months ended September 30, 2011, respectively, compared with the same periods in 2010. The following items had an unfavorable impact on Ameren’s electric margins for the three and nine months ended September 30, 2011, compared with the year-ago periods (except where a specific period is referenced):

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Net unrealized MTM losses principally at the Merchant Generation segment (primarily at Marketing Company), related to nonqualifying power hedges and fuel-related contracts for the quarter. However, the year-to-date activity was primarily driven by nonqualifying power hedges ($47 million and $42 million, respectively).

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Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes were flat and declined 1%, respectively, attributable to continued economic pressure, energy efficiency measures and customer conservation efforts ($6 million and $40 million, respectively).

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Lower sales prices at the Merchant Generation segment due to reductions in higher-margin sales 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 ($39 million and $40 million, respectively).

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Decreased utilization of Merchant Generation’s energy centers during the year-to-date period, when compared to the same period in 2010, primarily due to planned and unplanned outages. Decreased utilization resulted in a $25 million decline in non-rate regulated sales. This decline was offset by a $30 million decrease in production volume and other costs, which included a $12 million decline in fuel costs and an $18 million decline in emission allowance costs. Lower emission allowances costs were primarily attributable to the impairment of allowances in 2010. However, Ameren experienced increased utilization of Merchant Generation’s energy centers during the third quarter, when compared to the same period in 2010, which contributed to a $25 million increase in non-rate regulated sales. This increase in revenues was offset, in part, by a $1 million increase in production volume and other costs, which included an $11 million increase in fuel costs offset by a $10 million reduction in emission allowance costs.

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3% and 6% 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 $30 million, respectively).

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Lower wholesale sales at Ameren Missouri due to a reduction in customers, expiration of favorably priced contracts and the inclusion of the remaining contracts as an offset to fuel costs in the FAC beginning July 31, 2011 ($5 million and $37 million, respectively).

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Unfavorable weather conditions, as evidenced by a 4% decrease in cooling degree-days year-to-date compared with the same period in 2010, decreased year-to-date revenues by $19 million. However, favorable weather conditions, as evidenced by a less than 1% increase in cooling degree-days for the third quarter compared with the same period last year, increased revenues by $8 million. Weather conditions in Ameren’s service territory were warmer than normal as evidenced by a 20% increase in cooling degree-days for both the quarter and year-to-date periods.

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A $17 million reduction in revenues in the year-to-date period, 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. See Note 2 - Rate and Regulatory Matters under Part 1, Item 1, for further information regarding the FAC prudence review.

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Decreased recovery of prior years’ bad debt expense at Ameren Illinois, through the Illinois bad debt rider, which became effective in March 2010 ($6 million and $12 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 nine months ended September 30, 2011, compared with the year-ago periods (except where a specific period is referenced):

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Higher electric base rates at Ameren Missouri, effective June 2010 and July 2011 ($36 million and $138 million, respectively), offset by net base fuel expense ($- million and $25 million, respectively), which was a result of higher net base fuel cost rates approved in the 2010 and 2011 MoPSC rate orders. Net base fuel expense is the sum of fuel - production volume and other (-$14 million and -$32 million, respectively), purchased power (+$13 million and +$53 million, respectively), and off-system revenues (+$5 million and +$66 million, respectively) offset by the FAC under-recovery (-$4 million and -$112 million, respectively). See below for additional details regarding the FAC.

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Higher transmission revenues for the year-to-date period compared to the same period last year primarily associated with higher FERC-regulated transmission rates at Ameren Illinois. 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. However, transmission revenues were flat for the third quarter compared to the same period last year, due to lower rates effective in the second quarter of 2011, primarily as a result of warmer weather in 2010 ($- million and $22 million, respectively).

•

Higher electric delivery service rates at Ameren Illinois, effective in early May and November 2010 ($8 million and $18 million, respectively).

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Increased recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms at Ameren Illinois ($2 million and $14 million, respectively). See Operations and Maintenance in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.

Ameren’s revenues associated with Illinois pass-through power supply costs decreased because of lower power prices on sales primarily made with nonaffiliated parties. These revenues were offset by a corresponding net decrease in purchased power costs ($38 million and $90 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 and 2011 MoPSC rate orders, Ameren Missouri had a lower amount of under-recovered fuel costs to accrue as a regulatory asset for the three and nine months ended September 30, 2011, which resulted in an unfavorable impact on FAC under-recovery of $4 million and $112 million, respectively. The change in net recovery of fuel costs under the FAC recovered from customer rates was $26 million and $97 million, respectively, for the three and nine months ended September 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 increased by $1 million, or 1%, for the three months ended September 30, 2011, compared with the same period in 2010; however, natural gas margins decreased by $7 million, or 2%, for the nine months ended September 30, 2011, compared with the same period in 2010. The following items had an unfavorable impact on Ameren’s natural gas margins for the three and nine months ended September 30, 2011, compared with the year-ago periods:

•

Decreased recovery of prior years’ bad debt expense through the Illinois bad debt rider at Ameren Illinois, which became effective March 2010 ($5 million and $10 million, respectively). See Operations and Maintenance in this section for additional information on a related offsetting decrease in bad debt expense.

•

17% and 7% lower native load sales volumes, respectively, excluding the estimated impact of abnormal weather, largely in the commercial and industrial sectors, attributable to continued economic pressure ($- million and $4 million, respectively).

The following items had a favorable impact on Ameren’s natural gas margins for the three and nine months ended September 30, 2011, compared with the year-ago periods (except where a specific period is referenced):

•

Higher natural gas rates effective February 2011 at Ameren Missouri and effective May and November 2010 at Ameren Illinois ($3 million and $5 million, respectively).

•

Favorable weather conditions, as evidenced by a 3% increase in heating degree-days year-to-date compared to the same period in 2010, increased year-to-date revenues by $1 million. Compared to normal, Ameren experienced a 7% increase in heating degree-days year-to-date.

•

Increased recovery of energy efficiency and environmental remediation costs through Illinois rate-adjustment mechanisms at Ameren Illinois ($2 million and $1 million, respectively). See Operations and Maintenance in this section for information on a related offsetting increase in energy efficiency program costs and environmental remediation costs.

Ameren Missouri

Ameren Missouri has a FAC cost recovery mechanism as discussed in the Ameren margin discussion above.

Ameren Missouri’s electric margins increased by $28 million, or 4%, and $20 million, or 1%, for the three and nine months ended September 30, 2011, respectively, compared with the same periods in 2010. Ameren Missouri’s electric margins were favorably impacted by higher electric base rates, effective June 2010 and July 2011 ($36 million and $138 million, respectively), offset by net base fuel expense ($- million and $25 million, respectively), which was a result of higher net base fuel cost rates approved in the 2010 and 2011 MoPSC rate orders. Net base fuel expense is the sum of fuel - production volume and other (-$14 million and -$32 million, respectively), purchased power (+$13 million and +$53 million, respectively), and off-system revenues (+$5 million and +$66 million, respectively) offset by the FAC under-recovery (-$4 million and -$112 million, respectively).

The following items had an unfavorable impact on Ameren Missouri’s electric margins for the three and nine months ended September 30, 2011, compared with the year-ago periods (except where a specific period is referenced):

•

Lower wholesale sales due to a reduction in customers, expiration of favorably priced contracts and the inclusion of the remaining contracts as an offset to fuel costs in the FAC beginning July 31, 2011 ($5 million and $37 million, respectively).

•

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 ($8 million and $32 million, respectively).

•

A $17 million reduction in revenues in the year-to-date period, 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. See Note 2 - Rate and Regulatory Matters under Part 1, Item 1, for further information regarding the FAC prudence review.

•

Unfavorable weather conditions, as evidenced by a 3% decrease in cooling degree-days year-to-date compared with the same period in 2010, decreased revenues $14 million, however, favorable weather conditions, as evidenced by a 2% increase in cooling degree-days for the quarter compared with the same period last year, increased revenues $8 million. Weather conditions in Ameren Missouri’s service territory were warmer than normal as evidenced by a 19% and 20% increase in cooling degree-days for the quarter and year-to-date periods, respectively.

Ameren Missouri’s natural gas margins were flat for the three months ended September 30, 2011, compared with the same period in 2010; however, natural gas margins increased by $4 million, or 7%, for the nine months ended September 30, 2011, compared with the same period in 2010. Ameren Missouri’s natural gas margins were favorably impacted by higher natural gas rates, effective February 2011 ($1 million and $3 million, respectively).

Ameren Illinois Regulated Segment

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 $15 million, or 4%, and $31 million, or 4%, for the three and nine months ended September 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 nine months ended September 30, 2011, compared with the year-ago periods:

•

Higher electric delivery service rates, effective in early May and November 2010 ($8 million and $18 million, respectively).

•

Higher transmission revenues for the year-to-date period compared to the same period last year primarily associated with higher FERC-regulated transmission rates, which increased revenues $16 million. Higher rates were due, in part, to a significant increase in

transmission assets placed into service, higher equity levels as a result of Ameren’s capital contributions to Ameren Illinois, and mild 2009 weather, which all impacted the FERC transmission rates that became effective in the second quarter of 2010. However, transmission revenues were lower for the third quarter compared to the same period last year, due to lower rates effective the second quarter of 2011, primarily as a result of warmer weather in 2010, which lowered revenues $1 million.

•

Increased recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms ($2 million and $14 million, respectively). See Operations and Maintenance in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.

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

•

Decreased recovery of prior years’ bad debt expense under the Illinois bad debt rider, which became effective March 2010 ($6 million and $12 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 5% decrease in cooling degree-days year-to-date compared with the same period in 2010, decreased year-to-date revenues by $5 million. Weather conditions were comparable for the quarters ended September 30, 2011 and 2010. Weather conditions in Ameren Illinois’ service territory were warmer than normal as evidenced by a 21% and 20% increase in cooling degree-days for the quarter and year-to-date periods, respectively.

•

Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes declined less than 1% year-to-date compared to the same period in 2010, attributable to continued economic pressure, energy efficiency measures and customer conservation efforts, which decreased revenues by $8 million. However, rate-regulated retail sales volumes increased 2% for the quarter when compared to the same period last year, which increased revenues $2 million.

Ameren Illinois’ natural gas margins decreased by $1 million, or 1%, and $12 million, or 4%, for the three and nine months ended September 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 nine months ended September 30, 2011, compared with the year-ago periods:

•

Decreased recovery of prior years’ bad debt expense under the Illinois bad debt rider, which became effective March 2010 ($5 million and $10 million, respectively). See Operations and Maintenance in this section for additional information on a related offsetting decrease in bad debt expense.

•

Native load sales volumes declined by 16% and 7%, respectively, excluding the estimated impact of abnormal weather, largely in the commercial and industrial sectors, attributable to continued economic pressure ($1 million and $6 million, respectively).

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

•

Higher natural gas rates effective May and November 2010 ($2 million and $2 million, respectively).

•

Increased recovery of energy efficiency and environmental remediation costs through Illinois rate-adjustment mechanisms ($2 million and $1 million, respectively). See Operations and Maintenance in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.

•

Favorable weather conditions, as evidenced by a 3% increase in heating degree-days year-to-date compared to the same period in 2010, increased revenues $1 million. Compared to normal, Ameren Illinois experienced a 7% increase in heating degree-days year-to-date.

Merchant Generation

Merchant Generation’s electric margins decreased by $69 million, or 29%, and $101 million, or 17% for the three and nine months ended September 30, 2011, respectively, compared with the same periods in 2010.

Genco

Genco’s electric margins decreased by $26 million, or 18%, and $47 million, or 11%, for the three and nine months ended September 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 nine months ended September 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 resulted in an unfavorable price variance ($27 million and $36 million, respectively). However, the year-to-date period results were favorably impacted by the settlement of a contract dispute with a large customer in the second quarter of 2011.

•

3% and 5% higher fuel prices, respectively, primarily due to higher commodity and transportation costs associated with new supply contracts ($6 million and $22 million, respectively).

•

Decreased energy center utilization for the nine months ended September 30, 2011, when compared to the same period in 2010, primarily due to planned and unplanned outages. Genco’s lower production volume decreased electric revenues by $9 million, which was offset by a $20 million decline in production volume and other costs, which included a $5 million decline in fuel costs and a $15 million decline in emission allowance costs. Lower emission allowance costs were primarily attributable to the impairment of allowances in 2010. Genco’s average capacity factor remained unchanged at 71% year-to-date in 2011 compared with the same period in 2010, and Genco’s equivalent availability factor decreased to 84% year-to-date in 2011, compared with 86% year-to-date in 2010. However, Genco’s energy center utilization increased for the quarter compared to the same period last year. Genco’s higher production volume increased electric revenues by $20 million, which was offset, in part, by a $1 million increase in production volume and other costs, which included a $9 million increase in fuel costs net of an $8 million decline in emission allowance costs. Genco’s baseload coal-fired energy centers’ average capacity factor increased to 79% in the third quarter of 2011, compared with 72% in the third quarter of 2010, and Genco’s equivalent availability factor increased to 92% in the third quarter of 2011, compared with 89% in the third quarter of 2010.

•

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 ($17 million and $7 million, respectively).

Other Merchant Generation

Electric margins from Ameren’s other Merchant Generation operations, primarily AERG and Marketing Company, decreased by $43 million, or 49%, and $54 million, or 27%, for the three and nine months ended September 30, 2011, respectively, compared with the same periods in 2010. The following items had an unfavorable impact on Ameren’s other Merchant Generation operations’ electric margins for the three and nine months ended September 30, 2011, compared with the year-ago periods:

•

Unfavorable net unrealized MTM activity, principally at Marketing Company, largely related to nonqualifying power hedges ($30 million and $35 million, respectively).

•

Decreased energy center utilization at AERG, for the nine months ended September 30, 2011, when compared to the same period in 2010, primarily due to planned and unplanned outages. AERG’s lower production volume decreased electric revenues by $16 million, which was mitigated by a $10 million decline in production volume and other costs, which included $7 million of fuel cost and $3 million of emission allowances costs. AERG’s average capacity factor decreased to 75% year-to-date in 2011, compared with 76% year-to-date in 2010, and AERG’s equivalent availability factor decreased to 81% year-to-date in 2011, compared with 85% year-to-date in 2010. However, AERG’s energy center utilization increased for the quarter compared to the same period last year. AERG’s higher production volume increased electric revenues by $5 million. Production volume and other costs were comparable. Production volume and other costs included higher fuel cost of $2 million offset by lower emission allowances costs of $2 million. AERG’s baseload coal-fired energy centers’ average capacity factor increased to 84% in the third quarter of 2011, compared with 75% in the third quarter of 2010, and AERG’s equivalent availability factor increased to 91% in the third quarter of 2011, compared with 85% in the third quarter of 2010.

•

6% and 8% higher fuel prices at AERG, respectively, primarily due to higher commodity and transportation costs associated with new supply contracts ($2 million and $8 million, respectively).

•

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 lower market prices resulted in an unfavorable price variance ($12 million and $4 million, respectively). The decrease in the year-to-date period was mitigated by a favorable settlement of a contract dispute with a large customer in the second quarter of 2011.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren Corporation

Three months - Other operations and maintenance expenses decreased $23 million in the third quarter of 2011, compared with the same period in 2010.

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

•

A $13 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.

•

Write-offs in 2010 of $10 million due to canceled or unrecoverable projects at Ameren Missouri.

•

Labor costs decreased $6 million, primarily because of lower average compensation.

•

Plant maintenance costs decreased $5 million, primarily because of coal-fired energy center outages in the prior year.

Other operations and maintenance expenses increased due to an unfavorable change of $14 million in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.

Nine months - Other operations and maintenance expenses were $11 million higher in the first nine months of 2011, as compared with the first nine months of 2010.

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

•

A $35 million increase in storm-related repair costs, primarily due to major storms in 2011.

•

A $15 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.

•

An unfavorable change of $6 million in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.

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

•

Plant maintenance costs decreased by $34 million, primarily because of the timing of refueling and maintenance outages at the Callaway energy center between years. The 2011 refueling and maintenance outage began in October 2011. The 2010 refueling and maintenance outage occurred in the spring.

•

Write-offs in 2010 of $10 million due to canceled or unrecoverable projects at Ameren Missouri.

•

A $12 million decrease in bad debt expense. Bad debt expense decreased primarily because of adjustments under the Ameren Illinois bad debt rider mechanism.

•

A $5 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 nine months ended September 30, 2011, compared with the same periods in 2010, were as follows:

Ameren Missouri

Three months - Other operations and maintenance expenses decreased $15 million, because of items noted below and cost management efforts to align spending with regulatory outcomes and economic conditions.

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

•

Write-offs in 2010 of $10 million due to canceled or unrecoverable projects.

•

Plant maintenance costs decreased $4 million, primarily because of coal-fired energy center outages in the prior year.

•

Labor costs decreased $3 million, primarily because of lower average compensation.

Other operations and maintenance expenses increased due to an unfavorable change of $8 million in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.

Nine months - Other operations and maintenance expenses decreased $9 million, because of items noted below and cost management efforts to align spending with regulatory outcomes and economic conditions.

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

•

Plant maintenance costs decreased by $37 million, primarily because of the timing of refueling and maintenance outages at the Callaway energy center between years.

•

Write-offs in 2010 of $10 million due to canceled or unrecoverable projects.

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

•

A $21 million increase in storm-related repair costs, primarily due to major storms in 2011.

•

Other operations and maintenance expenses were reduced in the prior-year period by $11 million for the May 2010 MoPSC rate order, as noted above.

•

Ameren Illinois Regulated Segment

Three months - Other operations and maintenance expenses were comparable between periods as reduced bad debt expense, primarily because of adjustments under the Ameren Illinois bad debt rider mechanism, was offset by an unfavorable change in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans, and by increased energy efficiency and environmental remediation costs.

Nine months - Other operations and maintenance expenses increased $25 million. Energy efficiency and environmental remediation costs increased by $15 million, storm-related repair costs were higher by $14 million, and employee benefit costs increased by $7 million, primarily because of increased medical claims. Mitigating these unfavorable items was a reduction in bad debt expense of $13 million, primarily because of adjustments under the Ameren Illinois bad debt rider mechanism, and a reduction in non-storm-related distribution maintenance expenditures of $5 million due, in part, to the deployment of work crews to storm repair work.

Merchant Generation

Three months - Other operations and maintenance expenses were comparable at Genco and in the Merchant Generation Segment between periods.

Nine months - Other operations and maintenance expenses were comparable in the Merchant Generation segment as increased employee benefit costs, primarily pension costs, as well as increased plant maintenance costs at AERG, resulting from increased planned outages, mitigated the favorable impact of property sale gains at Genco. Other operations and maintenance expenses decreased $4 million at Genco, primarily because gains on property sales increased by $7 million compared to the year-ago period.

Goodwill, Impairment and Other Charges

The following table summarizes goodwill, impairment and other charges that occurred during the three and nine months ended September 30, 2011 and 2010:


Three Months	Long- lived assets		Obsolete Inventory and Severance		Emission Allowances		Goodwill		Total
2011:
AMO	$	89	$	-	$	-	$	-	$	89
Genco		26		9		-		-		35
Ameren	$	115	$	9	$	-	$	-	$	124
2010:
Genco	$	64	$	-	$	41	$	65	$	170
AERG		37		-		27		355		419
Ameren	$	101	$	-	$	68	$	420	$	589
Nine Months
2011:
AMO	$	89	$	-	$	-	$	-	$	89
Genco		26		9		1		-		36
AERG		-		-		1		-		1
Ameren	$	115	$	9	$	2	$	-	$	126
2010:
Genco	$	64	$	-	$	41	$	65	$	170
AERG		37		-		27		355		419
Ameren	$	101	$	-	$	68	$	420	$	589

See Note 17 - Goodwill and Other Asset Impairments under Part II, Item 8, of the Form 10-K for additional information about the 2010 impairment charges and see Note 1 - Summary of Significant Accounting Policies under Part I, Item 1, of this report for additional information about the 2011 impairment and other charges.

Ameren Corporation

Three and nine months - Goodwill, impairment and other charges decreased by $465 million and $463 million for the three and nine month periods, respectively. During the third quarter of 2011, Ameren Missouri and Genco recorded long-lived asset impairments and other charges, which are discussed individually below. Additionally, during the first nine months in 2011, Ameren and Genco recorded intangible asset impairment charges relating to emission allowances of $2 million and $1 million, respectively. Larger impairments were recorded during the third quarter of 2010, when Ameren recognized noncash, pretax impairment charges relating to goodwill, long-lived assets, and emission allowances within the Merchant Generation segment.

Ameren Missouri

Three and nine months - In July 2011, the MoPSC issued an electric rate order that disallowed the recovery of costs of enhancements relating to the rebuilding of the Taum Sauk energy center in excess of the amounts recovered from property insurance. As a result, Ameren Missouri recorded a pretax charge to earnings of $89 million during the third quarter of 2011. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for additional information on the disallowance, including Ameren Missouri’s appeal of the MoPSC’s July 2011 electric rate order. Ameren Missouri did not reflect an asset impairment charge on its statement of income during 2010.

Merchant Generation and Genco

Three and nine months - In October 2011, Resources Company announced that a total of four currently operating units at Genco’s Meredosia and Hutsonville energy centers will cease operating at the end of 2011. As a result of these closures, Ameren and Genco each recorded a charge to earnings in the third quarter of 2011 of $35 million. Larger impairments were recorded during the third quarter of 2010, when Ameren and Genco recognized noncash, pretax impairment charges relating to goodwill, long-lived assets, and emission allowances.

Depreciation and Amortization

Ameren Corporation

Three months - Ameren’s depreciation and amortization expenses were comparable between periods.

Nine months - Ameren’s depreciation and amortization expenses increased $14 million in the nine months ended September 30, 2011, compared with the same period 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 nine months ended September 30, 2011, compared with the same periods in 2010, were as follows:

Ameren Missouri

Three months - Depreciation and amortization expenses were comparable between periods.

Nine months - Depreciation and amortization expenses increased $17 million, primarily because of increased depreciation and amortization expense resulting from the installation of scrubbers at Ameren Missouri’s Sioux energy center and other capital additions along with 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 nine 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 months - Ameren’s taxes other than income taxes were comparable between periods.

Nine months - Ameren’s taxes other than income taxes increased $13 million in the nine months ended September 30, 2011, compared with the same period in 2010, primarily because of items noted below at Ameren Missouri.

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

Ameren Missouri

Three months - Taxes other than income taxes were comparable between periods.

Nine months - Taxes other than income taxes increased $16 million, primarily because of increased property taxes, due to higher state and local assessments and increased tax rates, and higher gross receipts taxes from increased sales.

Ameren Illinois Regulated Segment and Merchant Generation

Three and nine 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 months - Miscellaneous income, net of expenses, was comparable between periods.

Nine months - Miscellaneous income, net of expenses, decreased $15 million in the nine months ended September 30, 2011, as compared with the same period in 2010,

primarily because of a reduction in allowance for equity funds used during construction at Ameren Missouri, as discussed below.

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

Ameren Missouri

Three months - Miscellaneous income, net of expenses, was comparable between periods.

Nine months - Miscellaneous income, net of expenses, decreased $16 million, primarily because of reduced allowance for equity funds used during construction. Allowance for equity funds used during construction was higher in 2010, primarily due to scrubbers being constructed at Ameren Missouri’s Sioux energy center, which were placed in service in late 2010.

Ameren Illinois Regulated Segment and Merchant Generation

Three and nine 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 nine months - Interest charges decreased $17 million and $41 million, respectively, in the three and nine months ended September 30, 2011, as compared with the same periods in 2010, because of items noted below 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 nine months ended September 30, 2011, compared with the same periods in 2010, were as follows:

Ameren Missouri

Three months - Interest charges were comparable between periods.

Nine months - Interest charges decreased $5 million, primarily because of a reduction in interest charges associated with uncertain tax positions of $4 million, 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. 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.

Ameren Illinois Regulated Segment

Three and nine months - Interest charges decreased $4 million and $5 million, respectively, primarily because of the redemption of $150 million of senior secured notes in June 2011 and the redemption of $40 million of first mortgage bonds in September 2010.

Merchant Generation

Three and nine months - Interest charges decreased $7 million and $23 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 nine months - Interest charges decreased $5 million and $13 million, respectively, at Genco, primarily because of the maturity and repayment of $200 million of senior unsecured notes in November 2010.

Income Taxes

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


	Three Months						Nine Months
	2011			2010			2011			2010
Ameren		36	%		(507	)% ^(a)		37	%		75	% ^(a)
Ameren Missouri		35			35			35			35
Ameren Illinois		40			37			40			38
Genco		20			17	^(b)		44			(19	) ^(b)
Merchant Generation		10			7	⁽ ^c ⁾		45			-	⁽ ^c ⁾

(a)	The effective tax rate was 35% and 36% for the three and nine months ended September 30, 2010, after excluding the impact of the goodwill impairment charge, which is not deductible for income tax purposes.

(b)	The effective tax rate was 38% and 72% for the three and nine months ended September 30, 2010, after excluding the impact of the goodwill impairment charge, which is not deductible for income tax purposes.

(c)	The effective tax rate was 41% and 7% for the three and nine months ended September 30, 2010, after excluding the impact of the goodwill impairment charge, which is not deductible for income tax purposes.

Ameren Corporation

Three months - Ameren’s effective tax rate in the third quarter of 2011 was higher than the third quarter of 2010, primarily due to the impact of a non-deductible goodwill impairment charge on a pretax book loss in 2010, along with the impact of an increase in the Illinois statutory tax rate effective at the beginning of 2011.

Nine months - Ameren’s effective tax rate in the first nine months of 2011 was lower than the same period in 2010, primarily due to the impact of the non-deductible goodwill impairment charge in 2010. In addition, 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 offset, in part, by the impact of the increased 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 nine months ended September 30, 2011, compared with the same periods in 2010, were as follows:

Ameren Missouri

Three and nine months - Ameren Missouri’s effective tax rate was comparable between periods.

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 changes in reserves for uncertain tax positions in the current period.

Nine months - Ameren Illinois Regulated Segment’s effective tax rate was higher, primarily because of the increase in the Illinois statutory income tax rate at the beginning of 2011, along with unfavorable net amortization of property-related regulatory assets and liabilities in 2011, compared with favorable amortization in 2010, offset, in part, by the effect of the change in tax treatment of retiree health care costs in 2010.

Merchant Generation

Three months - The effective rate was higher in the Merchant Generation segment, primarily because of the increase in the Illinois statutory income tax rate in 2011, along with the impact of the non-deductible goodwill impairment charge in 2010 on a pretax book loss, offset, in part, by changes in reserves for uncertain tax positions along with the impact of the manufacturing deduction on a lower pretax book loss in 2011.

Nine months - The effective tax rate was higher in the Merchant Generation segment, primarily because of the increase in the Illinois statutory income tax rate in 2011, along with the impact of the non-deductible goodwill impairment charge on a pretax book loss in 2010, offset, in part, by favorable changes to reserves for uncertain tax positions in 2011, compared to unfavorable changes in 2010.

Genco

Three months - Genco’s effective tax rate was higher, primarily because of the increase in the Illinois statutory income tax rate in 2011, along with the impact of the non-deductible goodwill impairment charge on a pretax book loss in 2010, offset, in part, by the impact of a lower favorable manufacturing deduction on a pretax book loss.

Nine months - Genco’s effective tax rate was higher, primarily because of the impact of the non-deductible goodwill impairment charge on a pretax book loss in 2010, along with the increase in the Illinois statutory income tax rate in 2011 and the decrease in the effective tax rate from the effect of the change in the tax treatment of retiree health care costs in 2010 on a pretax book loss.

Income from Discontinued Operations, Net of Tax

Ameren Illinois

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 nine months ended September 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)	$	1,566	$	1,496	$	70		$	(757	)	$	(776	)	$	19		$	(832	)	$	(734	)	$	(98	)
Ameren Missouri		854		778		76			(459	)		(481	)		22			(241	)		(273	)		32
Ameren Illinois		438		459		(21	)		(212	)		(183	)		(29	)		(432	)		(297	)		(135	)
Genco		179		293		(114	)		(101	)		(185	)		84			(76	)		(107	)		31

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

•

Ameren Missouri’s regulatory asset for FAC under-recovery decreased by $237 million as more deferred costs were recovered from customers during 2011.

•

Deferred budget billing receivables decreased by $69 million, partially as a result of milder weather.

•

A $61 million decrease in collateral posted with counterparties due primarily to the items discussed at the registrant subsidiaries below, partially offset by increased postings of $43 million by Ameren and Marketing Company due to changes in the market price of power.

•

A $31 million reduction in expenditures due to the timing of scheduled nuclear refueling and maintenance outages at the Callaway energy center.

•

A $29 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.

•

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.

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

•

A $105 million increase in pension and OPEB plan contributions. Ameren Illinois contributed to Ameren’s postretirement benefit VEBA trust an incremental $100 million in excess of Ameren Illinois’ annual postretirement net periodic cost for regulatory purposes.

•

During 2010, Ameren’s coal-fired energy centers, primarily at the Merchant Generation segment, significantly reduced their coal inventory levels, which resulted in an estimated $59 million cash savings in excess of the smaller inventory reduction that occurred in 2011.

•

A $58 million decrease associated with the December 2005 Taum Sauk incident, primarily as a result of insurance recoveries received in 2010, but not in 2011.

•

A $39 million decrease in income tax refunds. The 2010 refund resulted primarily from a 2009 change in tax treatment of electric generation plant expenditures while the 2011 refund resulted primarily from casualty loss deductions due to an Internal Revenue Service audit settlement.

•

A $34 million increase in major storm restoration costs.

•

A $17 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.

•

A $15 million increase in energy efficiency expenditures for new customer programs. The Ameren Illinois amount is recovered through customer billings and offset by increased margins.

•

A $13 million decrease in natural gas commodity over-recovered costs under the PGA, primarily in Illinois.

•

An $11 million increase in property tax payments caused primarily by higher assessed tax values and rates in Missouri.

•

Reduced collection results as more utility customers were past due on their bills as of September 30, 2011, compared with September 30, 2010. Additionally, write-offs of customer receivable balances have increased due to economic conditions.

•

Electric and natural gas margins, as discussed in Results of Operations, decreased by $8 million, excluding impacts of noncash MTM transactions.

Ameren Missouri

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

•

The regulatory asset for FAC under-recovery decreased by $237 million as more deferred costs were recovered from customers during 2011.

•

A $31 million reduction in expenditures due to the timing of scheduled nuclear refueling and maintenance outages at the Callaway energy center.

•

Deferred budget billing balances decreased by $27 million, partially as a result of milder weather.

•

Electric and natural gas margins, as discussed in Results of Operations, increased by $25 million, excluding impacts of noncash MTM transactions.

•

A $4 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 nine months of 2011, compared with the same period in 2010:

•

Income tax payments of $2 million in 2011, compared with income tax refunds of $74 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 $58 million decrease associated with the December 2005 Taum Sauk incident, primarily as a result of insurance recoveries received in 2010, but not in 2011.

•

A $21 million increase in major storm restoration costs.

•

A $17 million increase in receivables held in court registries under the appeals of the MoPSC’s 2009 and 2010 rate orders.

•

A $13 million increase in collateral posted with counterparties due, in part, to changes in the market price of power and natural gas.

•

Reduced collections results as more customers were past due on their bills as of September 30, 2011, compared with September 30, 2010. Additionally, write-offs of customer receivable balances have increased due to economic conditions.

•

A $7 million increase in energy efficiency expenditures for new customer programs.

•

A $6 million increase in property tax payments, caused primarily by higher assessed tax values and rates.

Ameren Illinois

Ameren Illinois’ cash from operating activities decreased in the first nine months of 2011 compared with the first nine months of 2010. Ameren Illinois’ cash from operating activities included AERG’s operating cash flows for all periods prior to October 1, 2010, which were presented as discontinued operations in Ameren Illinois’ consolidated statement of cash flows. Excluding the impacts of discontinued operations, Ameren Illinois’ cash from operating activities increased in the first nine months of 2011 compared with the first nine months of 2010. The following items contributed to the increase in cash from operating activities associated with continuing operations during the first nine months of 2011, compared with the same period in 2010:

•

A $117 million decrease in collateral posted with counterparties due, in part, to changes in the market price of natural gas and a reduction in contracted volumes.

•

An increase in cash collected in 2011 from receivables originating from revenues earned in 2010, compared with 2009 revenues collected in 2010. At December 31, 2010, trade receivables and unbilled revenues were $47 million higher than they were at December 31, 2009, primarily because of higher utility rates and a colder December in 2010, compared with December 2009. The September 30, 2011 and 2010 balances of trade receivables and unbilled revenues were comparable.

•

Deferred budget billing balances decreased by $42 million, partially as a result of milder weather.

•

Electric and natural gas margins, as discussed in Results of Operations, increased by $19 million, excluding impacts of noncash MTM transactions.

•

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

•

A $5 million decrease in interest payments, primarily due to the redemption of first mortgage bonds in September 2010.

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

•

A $97 million increase in pension and OPEB plan contributions as an incremental voluntary contribution was made in 2011.

•

A $13 million increase in major storm restoration costs.

•

A MISO billing adjustment during the third quarter of 2011, resulted in the accelerated payment of $11 million, which would have otherwise been paid in the fourth quarter of 2011.

•

A $10 million decrease in natural gas commodity over-recovered costs under the PGA.

•

An $8 million increase in energy efficiency expenditures for new customer programs. These expenditures are recovered through customer billings and offset by increased margins.

•

Reduced collection results as more customers were past due on their bills as of September 30, 2011, compared with September 30, 2010. Additionally, write-offs of customer receivable balances have increased due to economic conditions.

•

A $5 million increase in non-income tax payments, primarily for electricity distribution and invested capital taxes.

•

A $5 million decrease in income tax refunds, primarily caused by a reduction in transmission and distribution repair deductions in 2011, partially offset by additional casualty loss deductions from an Internal Revenue Service audit settlement.

Genco

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

•

During 2010, Genco significantly reduced the volume of its coal inventory, which resulted in an estimated $47 million cash savings in excess of the smaller inventory reduction that occurred in 2011.

•

Electric margins, as discussed in Result of Operations, decreased by $40 million, excluding impacts of noncash MTM transactions.

•

The January 2010 receipt from Marketing Company under Genco’s power supply agreement with Marketing Company for its December 2009 generation output was $16 million higher than the January 2011 receipt for its December 2010 generation output, primarily caused by the inclusion of higher-priced sales contracts from the 2006 Illinois power procurement auction, which expired in May 2010.

•

A $9 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.

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

•

Income tax refunds of $3 million in 2011, compared with income tax payments of $22 million in 2010. The 2011 refund was primarily due to an increase in accelerated depreciation deductions authorized by the economic stimulus legislation.

•

A $10 million decrease in interest payments, primarily due to the redemption of senior notes in November 2010.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities decreased during the first nine months of 2011, compared with the same period in 2010. In 2011, cash flows from investing activities benefited from an increase of proceeds from property sales as well as $8 million in proceeds from the sale of its investment in a leveraged lease and a $9 million payment received from the DOE under the terms of Ameren Missouri’s settlement with the DOE related to nuclear waste disposal. The 2011 cash benefit from these items was principally offset by an increase in nuclear fuel expenditures related to the timing of purchases. Net cash used for capital expenditures during the first nine months of 2011 was comparable to the same period in 2010. Reductions in capital expenditures

caused by the completion of two energy center scrubber projects in 2010 were offset, in part, by an increase in storm restoration costs and expenditures for a third energy center scrubber project in 2011.

Ameren Missouri’s cash used in investing activities decreased during the first nine months of 2011, compared with the same period in 2010, principally because of a $43 million decrease in capital expenditures and a $9 million payment received from the DOE in 2011 under the terms of the settlement with the DOE related to nuclear waste disposal. Capital expenditures were lower in 2011 as a result of the completion in 2010 of two scrubbers at Ameren Missouri’s Sioux energy center and boiler projects, which offset a $28 million increase in capital expenditures related to storm restoration costs. This cash benefit was reduced by a $21 million increase in nuclear fuel expenditures related to the timing of purchases.

Ameren Illinois’ cash used in investing activities increased during the first nine months of 2011, compared with the same period in 2010, principally because of a $46 million increase in capital expenditures primarily as a result of increased investment in new transmission lines and a $17 million increase in capital expenditures related to storm restoration costs. In 2011, cash flows from investing activities benefited from the repayments of advances previously paid to ATXI, as a result of the completion of a project under a joint ownership agreement. In 2010, cash flows from investing activities benefited from the proceeds received on an intercompany note receivable.

Genco’s cash used in investing activities decreased during the first nine months of 2011, compared with the same period in 2010, because of a decrease in money pool advances and an increase in proceeds from sales of properties offset by an increase in capital expenditures. During the 2010 period, cash savings related to efforts to reduce, defer or cancel capital expenditure programs enabled Genco to contribute net non-state-regulated subsidiaries’ money pool advances of $132 million. In 2011, Genco contributed advances of $38 million. 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 remaining interest in its Columbia CT facility. In 2010, cash flows from investing activities benefited from the proceeds received from the sale of 25% of Genco’s Columbia CT facility. Net cash used for capital expenditures increased by $41 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 Genco’s Newton energy center scrubber project.

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 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. The Merchant Generation segment further reduced its estimated capital expenditures compared to those estimates disclosed in the Form 10-Q for the period ended June 30, 2011. 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. In October 2011, Resources Company announced that Genco’s Meredosia and Hutsonville energy centers will cease operating at the end of 2011. The closure of these two energy centers has allowed the Merchant Generation segment additional flexibility in the methods to achieve compliance with environmental standards. 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		145			475	-		555		620	-		700
Other ^(a)		(10	)		520	-		605		510	-		595
Ameren ^(b)	$	1,135		$	5,145	-	$	5,990	$	6,280	-	$	7,125

(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 nine months ended September 30, 2011, compared with the same period in 2010. In 2011 and 2010, Ameren utilized the surplus of net cash provided by operating activities in excess of net cash used in investing activities to fund common stock dividends and repay financing obligations. During the nine months ended September 30, 2011, Ameren increased its net refunds of advances previously received from generators by $55 million due to project completion and increased its net repayments of short-term debt and credit facility borrowings by $54 million, 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 and operating cash flows. Efforts to reduce, defer and cancel expenditures during the first nine months of 2010 allowed Ameren to redeem $106 million of long-term debt and $52 million of preferred stock.

Ameren Missouri’s net cash used in financing activities decreased during the nine months ended September 30, 2011, compared with the same period in 2010. In 2010, Ameren Missouri redeemed $66 million of long-term debt and $33 million of preferred stock. In 2011, net refunds of advances previously received from generators increased $29 million due to project completion, and common stock dividends increased $43 million, compared with the same period in 2010.

Ameren Illinois’ net cash used in financing activities increased during the nine months ended September 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. In 2010, Ameren Illinois redeemed $40 million of long-term debt and $19 million of preferred stock. Additionally, in 2011, common stock dividends increased $138 million and net refunds of advances previously received from generators increased $25 million due to project completion, compared with the same period in 2010. 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 $107 million for financing activities.

Genco’s net cash used in financing activities decreased during the nine months ended September 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 borrowing obligations. In 2011, Genco repaid credit facility borrowings of $100 million, while in 2010, it made a $103 million payment on an intercompany note payable to Ameren. In 2011, the net repayment of credit facility borrowings was offset, in part, 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 September 30, 2011:


	Expiration	Amount Committed		Credit Available
Ameren and Ameren Missouri:
2010 Missouri Credit Agreement ^(a)	September 2013	$	800	$	800
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


	Expiration	Amount Committed		Credit Available
Ameren:
$20 million revolving credit facility	June 2012		20		-
Less:
Commercial paper outstanding					(330	)
Letters of credit					(15	)
Total		$	2,120	$	1,755

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

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 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.

Long-term Debt and Equity

The following table presents the issuances of common stock and the maturities of long-term debt for the nine months ended September 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, Redeemed, Repurchased or Matured	Nine Months
	Month Issued, Redeemed, Repurchased or Matured	2011		2010
Issuances
Common stock
Ameren:
DRPlus and 401(k)	Various	$	49	$	60
Total common stock issuances		$	49	$	60
Redemptions, Repurchases and Maturities
Long-term debt
Ameren Missouri:
7.69% Series A subordinated deferrable interest debentures due 2036	September	$	-	$	66
Ameren Illinois:
6.625% Senior secured notes due 2011	June		150
7.61% Series 1997-2 first mortgage bonds due 2017	September		-		40
Total Ameren long-term debt redemptions, repurchases and maturities		$	150	$	106
Preferred stock
Ameren Missouri:
$7.64 Series	August	$	-	$	33


	Month Issued, Redeemed, Repurchased or Matured	Nine Months
	Month Issued, Redeemed, Repurchased or Matured	2011		2010
Ameren Illinois:
4.50% Series	August		-		11
4.64% Series	August		-		8
4.08% Series ^(a)	September		-		7
4.20% Series ^(a)	September		-		5
4.26% Series ^(a)	September		-		4
4.42% Series ^(a)	September		-		3
4.70% Series ^(a)	September		-		5
7.75% Series ^(a)	September		-		9
Total Ameren preferred stock redemptions and repurchases		$	-	$	85
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities		$	150	$	191

(a)	In September 2010, Ameren contributed to the capital of Ameren Illinois (formerly IP), without the payment of any consideration, the IP preferred stock owned by Ameren ($33 million). IP canceled these preferred shares.

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 $17 million and 1.8 million new shares of common stock valued at $49 million in the three and nine months ended September 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 credit facilities and in certain of the Ameren Companies’ indentures and articles of incorporation.

At September 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 $279 million, or $1.155 per share, during the first nine months of 2011 (2010 - $276 million or $1.155 per share). On October 14, 2011, Ameren’s board of directors declared a quarterly common stock dividend of 40 cents per share payable on December 30, 2011, to stockholders of record on December 7, 2011. The board’s action resulted in an annualized equivalent dividend rate of $1.60 per share. The previous annualized equivalent dividend rate was $1.54 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 September 30, 2011, none of these circumstances existed at the Ameren Companies and, as a result, the Ameren Companies were allowed to pay dividends.

The following table presents common stock dividends paid by Ameren Corporation to its common stockholders and by Ameren’s registrant subsidiaries to their parent, Ameren, for the nine months ended September 30, 2011, and 2010:


	Nine Months
	2011		2010
Ameren Missouri	$	219	$	176
Ameren Illinois		238		100
Ameren		279		276

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 September 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 $9,683 million, $5,904 million, $2,610 million, and $760 million, respectively. The above stated amounts include multi-year agreements to procure ultra low-sulfur coal and the related transportation from Wyoming’s Powder River Basin 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 September 30, 2011, which were not included in the totals above, for Ameren, Ameren Missouri, Ameren Illinois and Genco were $189 million, $144 million, $30 million, and $11 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 natural 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 September 30, 2011, were $131 million, $14 million, $89 million, and $1 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 September 30, 2011. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at September 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 $230 million, $53 million, $117 million, and $14 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments at current credit ratings. If market prices were 15% higher than September 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 $180 million, $4 million, $- million, and $21 million, respectively. If market prices were 15% lower than September 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 $192 million, $7 million, $63 million, and $71 million, respectively.

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

OUTLOOK

Ameren’s goal is to earn competitive returns on investments in its businesses. Ameren Missouri and Ameren Illinois are seeking to enhance their regulatory frameworks and cost recovery mechanisms so that they can earn fair returns. Ameren Missouri and Ameren Illinois are also pursuing constructive regulatory outcomes within existing frameworks and are aligning their overall spending, both operating and capital, with economic conditions and regulatory outcomes and cash flows provided by their regulators. Consequently, Ameren’s rate-regulated businesses expect to narrow the historic gap between allowed and earned returns on equity. Ameren’s Merchant Generation segment maintains a fleet of competitive generating assets. Ameren’s merchant generation strategy is to position the company as a low-cost provider to position it to benefit from an expected recovery of power prices. Ameren intends to allocate its capital resources to those business opportunities, including electric and natural gas transmission, that offer the most attractive risk-adjusted return potential.

Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity as well as its ability to achieve strategic and financial objectives for the remainder of 2011 and beyond.

Economy and Capital and Credit Markets

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Economic recovery within the service territory of the Ameren Companies continues to be slow, negatively impacting electrical loads. 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.

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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 September 30, 2011, the actual return on investment of the pension plan assets and postretirement plan assets underperformed the expected return. To the extent the actual return on investment of Ameren’s pension and postretirement plan assets do not achieve their expected return, additional expense will be recognized and additional contributions will be required in subsequent years. Ameren’s future expenses and contributions will also be affected by future discount rate levels. Based on preliminary projections, Ameren’s pension and postretirement expense will increase in 2012.

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The Ameren Companies continue to have access to the capital markets at commercially acceptable rates. 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.

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Ameren estimates its cash and cash equivalents will exceed its short-term debt and credit facility borrowings at December 31, 2011.

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In October 2011, Ameren’s board of directors declared a fourth quarter dividend of 40 cents per common share, a 3.9% increase from the prior quarterly dividend rate of 38.5 cents per share, resulting in an annualized equivalent dividend rate of $1.60 per share. On an annual basis, the dividend increase, at current outstanding common stock levels, will result in additional dividends of $15 million.

Current Capital Expenditure Plans

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Between 2011 and 2020, Ameren currently expects to invest up to $2.3 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 returns on the investments, 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.

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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 further closure of coal-fired energy centers, impairment of assets, or otherwise materially adversely affect Ameren’s results of operations, financial position, and liquidity. In October 2011, Genco announced that its Meredosia and Hutsonville energy centers will cease operating at the end of 2011 primarily due to the expected cost of complying with CSAPR. See Note 9 - Commitments and Contingencies under Part I, Item 1, of this report for further discussion of environmental matters.

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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.

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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 September 30, 2011, Ameren Missouri had capitalized approximately $68 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.

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In December 2011, 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.

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ATX intends to build projects initially within Illinois and Missouri, with the potential for expanding to other areas in the future. MISO approval for the first three ATX projects is anticipated in December 2011. The first project is Illinois Rivers and involves building a 345 kilovolt line across the state of Illinois, from the Missouri border to the Indiana border. The Spoon River project in northwest Illinois and the Mark Twain project in northeast Missouri are the other two projects being considered by MISO in its current transmission expansion plan. The total investment in these three projects is expected to be more than $1.2 billion through 2020, with potential investment of $400 million from 2011 to 2015. FERC, in its order issued in May 2011, approved transmission rate incentives for ATX, Ameren Missouri and Ameren Illinois for the Illinois River project as well as the Big Muddy project. The Big Muddy project is located primarily in southern Illinois and will be further evaluated in future MISO expansion plans.

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In September 2010, Resources Company announced that it signed a cooperative agreement with the DOE that could lead to repowering unit 4 at Genco’s Meredosia energy center. This would create the world’s first full-scale, oxy-combustion coal-fired plant designed for permanent CO ₂ capture and storage. During the third quarter of 2011, Ameren and two independent companies concluded their assessment of the project to validate its scope, cost, schedule and commercial viability. Resources Company is currently evaluating the results of the assessment and whether to continue beyond the current phase of this project.

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

Revenues

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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 addition, in future rate cases and through the legislative process, Ameren 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.

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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 2010 for $15 million and November 2010 for $25 million.

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Ameren Illinois filed a request with the ICC in February 2011, as subsequently revised, to increase its annual revenues for electric delivery service by $39 million and for natural gas delivery service by $50 million. In response to Ameren Illinois’ filed requests, the ICC staff recommended a net increase in revenues for electric delivery service of $4 million and a net increase in revenues for natural gas delivery service of $29 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 in January 2012.

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In October 2011, the Energy Infrastructure Modernization Act was enacted into law and became effective immediately. Also, in October 2011, House Bill 3036, which, if enacted, would result in certain amendments to the Energy Infrastructure Modernization Act, was passed by the Illinois General Assembly. The Energy Infrastructure Modernization Act applies to certain electric utilities in Illinois on an opt-in basis. This law includes a performance-based formula process for determining rates that would provide for the recovery of actual costs of electric delivery service that are prudently incurred, reflect the utility’s actual regulated capital structure, and include a formula for calculating the return on equity component of the cost of capital. House Bill 3036 modified the equity component of the formula rate to be based on the yields of 30-year United States treasury bonds plus 580 basis points, instead of 600 basis points. Participating utilities are subject to certain performance standards whereby the failure to achieve the standards will result in a reduction in the utility’s allowed return on equity calculated under the formula. Ameren Illinois would be required to invest $625 million in capital expenditures incremental to Ameren Illinois’ average capital expenditures for calendar years 2008 through 2010 over the next ten years to modernize its distribution system. Such investments are expected to encourage economic development and create an estimated 450 additional jobs within Illinois. Additionally, we believe this law would better enable Ameren Illinois to earn its allowed return on equity for its electric delivery service business. Ameren Illinois will also be required to make a one-time $7.5 million non-recoverable donation to the Illinois Science and Energy Innovation Trust, as well as a $1 million annual donation to the trust for as long as it is under the formula ratemaking process. House Bill 3036 also would require Ameren Illinois to contribute $1 million annually for customer assistance programs for as long as it is under the formula ratemaking process as well as require Ameren Illinois to withdraw its pending electric delivery service rate case. To become law, House Bill 3036 must be approved by the Illinois Governor, or if the Illinois Governor elects to veto the legislation, the Illinois General Assembly would have to override the veto. The formula ratemaking process is effective until the end of 2017, but could be extended by the Illinois General Assembly for an additional five years. Ameren Illinois is reviewing the final version of this law and House Bill 3036 to determine their potential impacts on Ameren’s and Ameren Illinois’ results of operations, financial position, and liquidity.

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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. Thereafter, Ameren Illinois

reached an agreement with one additional wholesale customer; however, the impasse with the remaining seven wholesale customers has resulted in litigation of this proceeding. An initial decision by the FERC administrative law judge is expected in 2012; however, a final decision may be received after 2012. 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.

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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 directed to deposit the contested amounts into the court’s registry and, as of September 30, 2011, had deposited $18 million in this account. In November 2011, the Missouri Court of Appeals issued a ruling that upheld the MoPSC’s January 2009 electric rate order. Noranda and MoOPC could request further appeals by early 2012. If the MoPSC’s January 2009 electric rate order is ultimately upheld, Ameren Missouri will receive all of the funds held in the Stoddard County Circuit Court’s registry, plus accrued interest. As a result of the Missouri Court of Appeals ruling, Ameren Missouri anticipates that the Stoddard County Circuit Court will release to Ameren Missouri the amount held in its registry by early 2012, depending on additional court proceedings. 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 September 30, 2011, the four industrial customers have made payments, excluding the bond amount, totaling $14 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 or in early 2012. 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.

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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. 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. 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. Ameren Missouri appealed the disallowance of Taum Sauk enhancements to the Missouri Court of Appeals, Western District. MIEC also appealed certain aspects of the MoPSC’s electric rate order to the Missouri Court of Appeals, Western District. A decision is expected by the Missouri Court of Appeals, Western District, in 2012. Ameren Missouri cannot predict the ultimate outcome of these appeals. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for additional information.

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

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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. 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 late 2011 or in 2012. 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’s FAC prudence review for the period from October 1, 2009, to May 31, 2011, was initiated in September 2011. On October 28, 2011, the MoPSC staff filed a recommendation with the MoPSC to direct Ameren Missouri to refund to customers the pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC staff calculated these pretax earnings to be $26 million. We cannot predict whether the MoPSC will approve this recommendation. 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. Because of pending court appeals and regulatory review, Ameren Missouri does not believe these amounts are currently probable of refund to customers.

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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.

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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 and 32.5 million megawatthours in 2011 and 2012, respectively. 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.

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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 September 30, 2011, Marketing Company had hedged approximately 27.5 million megawatthours of Merchant Generation’s expected generation for 2011, at an average price of $45 per megawatthour. For 2012, Marketing Company had hedged approximately 21.5 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $46 per megawatthour. For 2013, Marketing Company had hedged approximately 11 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $41 per megawatthour. As of September 30, 2011 Marketing Company had 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. 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.

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The development of a capacity market in MISO could impact 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 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.

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Current and future energy efficiency programs developed by Ameren Missouri, Ameren Illinois and others have and will continue to result in reduced demand for our electric generation and our electric and natural gas transmission and distribution services. Ameren Missouri’s regulatory framework currently allows for a return on energy efficiency expenditures similar to the return that could be earned on supply-side investments. In future rate proceedings, Ameren Missouri will also seek a regulatory framework that allows for the recovery of fixed costs within a declining demand environment. At Ameren Illinois, energy efficiency costs that are expensed are recovered through a rider mechanism to receive a return of investment from customers while capitalized costs earn a return similar to supply-side investments.

Fuel and Purchased Power

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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. Earlier in 2011, flooding in the Midwest, certain other railroad-related transportation disruptions, and a higher than forecasted summer burn reduced coal deliveries below normal levels at certain energy centers. However, as of September 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.

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Ameren’s fuel costs (including transportation) are expected to increase in 2011 and beyond. As of September 30, 2011, Merchant Generation had hedged fuel costs (including transportation) for approximately 29 million megawatthours at about $23 per megawatthour. For 2012, Merchant Generation had hedged fuel costs for approximately 25 million megawatthours of coal and up to 28 million megawatthours of base transportation at about $24 per megawatthour. For 2013, Merchant Generation had hedged fuel costs for approximately 11 million megawatthours of coal and up to 9 million megawatthours of base transportation 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

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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. See Note 2 - Rate and Regulatory Matters and Note 9 - Commitments and Contingencies under Part I, Item 1, of this report for further discussion of Taum Sauk matters.

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Ameren Missouri’s Callaway energy center is currently conducting a scheduled refueling and maintenance outage. This refueling and maintenance outage is scheduled 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.

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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 related areas, which Ameren and Ameren Missouri are currently reviewing. 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.

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The Illinois corporate income tax rate increased 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).

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Genco’s Meredosia and Hutsonville energy centers will cease operating by the end of 2011. Because of the resulting reduced operations and maintenance expense, and reduced depreciation expense, and because of the impact of currently weak power prices on electric margins, Ameren and Genco do not expect the closure of the Meredosia and Hutsonville energy centers to negatively impact their future earnings or cash flows compared with their expected 2011 earnings and cash flows.

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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 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 operations, financial position, and liquidity.

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On October 21, 2011, Ameren announced that, as part of its efforts to reduce its operations and maintenance expenses, it is extending a voluntary separation offer to approximately 715 management and labor union-represented employees who are 58 years of age or older as of December 31, 2011. This program is being offered to eligible employees at Ameren Missouri and at Ameren Services. Employees who accept the separation offer will receive benefits consistent with Ameren’s standard management severance benefits. Employees must decide whether to accept the separation offer by December 22, 2011, and those accepting are expected to leave their employment by December 31, 2011.

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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

•

Several collective bargaining agreements between Ameren subsidiaries and the IBEW, IUOE, the LIUNA, and the UA labor unions, covering approximately 925 employees, have expired or will expire in 2011. Contracts with multiple unions expired on June 30, 2011; however, those agreements were extended or are being extended while negotiations continue. Certain of the Ameren subsidiaries are seeking cost savings related to certain benefit provisions in light of the current challenging economic environment. In October 2011, Ameren and Genco reached agreement with IBEW, which represents approximately 110 employees, on a four-year agreement. In November 2011, Ameren reached an agreement, subject to ratification, with another union, which represents approximately 120 employees, on a four-year agreement. In 2012, several other collective bargaining agreements, covering approximately 3,400 employees, will expire. Any labor disputes that result in a work stoppage could have a material adverse effect on the Ameren Companies’ results of operations, financial position and liquidity.

•

As of September 30, 2011, Ameren expects to have approximately $480 million in federal income tax net operating loss carryforwards (Ameren Missouri - $60 million, Ameren Illinois - $170 million, Genco - $60 million) and $70 million in federal income tax credit carryforwards (Ameren Missouri - $11 million, Ameren Illinois - $- million, Genco - $1 million). These carryforwards are expected to be utilized to satisfy income tax liabilities through the end of 2013 (Ameren Missouri – 2012, Ameren Illinois – 2012, Genco – 2013).

•

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 United States health care system. The Ameren Companies are evaluating the long-term effects of this reform and the health care benefits they currently offer their employees and retirees. Additionally, Ameren will continue to monitor and assess the impact of the health care reforms, including any clarifying regulations issued to address how the provisions are to be implemented. Until those reviews are completed, Ameren is unable to estimate the effects of the new law on its results of operations, financial position, and liquidity.

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

REGULATORY MATTERS

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

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

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

Interest Rate Risk

We are exposed to market risk through changes in interest rates. The following table presents the estimated increase in our annual interest expense and decrease in annual net income that would result if interest rates on variable-rate debt outstanding at September 30, 2011, were to increase by 1%:


	Interest Expense			Net Income ⁽ ^a)
Ameren ^(b)	$	6		$	(3	)
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 September 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 September 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 September 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 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 $40 million at September 30, 2011 (2010 - $28 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 power, emission allowances, coal, diesel, natural gas and uranium.

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)	$	(18	)
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. MISO’s Indiana Hub is expected to be the replacement to the Cinergy Hub. 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, more 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, 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 term of contracts. 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 $15 million annually, before consideration of the FAC (Ameren Missouri - $8 million, Genco - $5 million). As of September 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 89% 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 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 their 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 September 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 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) ^(c)		99	%		96	%		61	%
Coal transportation ^(b) ^(c)		100			100			62
Nuclear fuel		100			100			84
Natural gas for generation		100			10			-
Natural gas for distribution ⁽ ^d ⁾		80			34			15
Purchased power for AIC ⁽ ^e ⁾		100			85			23
Ameren Missouri:
Coal ^(b)		99	%		100	%		88	%
Coal transportation ^(b)		100			100			97
Nuclear fuel		100			100			84
Natural gas for generation		100			2			-
Natural gas for distribution ⁽ ^d ⁾		77			24			12
Ameren Illinois:
Natural gas for distribution ⁽ ^d ⁾		80	%		36	%		16	%
Purchased power ⁽ ^e ⁾		100			85			23
Genco:
Coal ^(c)		100	%		80	%		22	%
Coal transportation ⁽ ^c)		100			100			9
Natural gas for generation		100			-			-

(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 Wyoming’s Powder River Basin. The percentages above include the low-sulfur coal agreement and related transportation agreement.

(c)	Ameren’s and Genco’s percentages of the projected required supply of coal and coal transportation have been adjusted to reflect the ceasing of operations at the Meredosia and Hutsonville energy centers effective December 31, 2011.

(d)	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.

(e)	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)	$	8		$	(5	)	$	10		$	(6	)
AMO ^(c)		(d	)		(d	)		(d	)		(d	)
Genco		6			(4	)		8			(5	)

(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 nine months ended September 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

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 September 30, 2011	Ameren ^(a)			Ameren Missouri			Ameren Illinois			Genco			Other ^(b)
Fair value of contracts at beginning of period, net	$	53		$	45		$	(315	)	$	21		$	302
Contracts realized or otherwise settled during the period		4			(1	)		63			(4	)		(54	)
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-
Fair value of new contracts entered into during the period		(26	)		(7	)		(7	)		(1	)		(11	)
Other changes in fair value		(30	)		(19	)		3			(8	)		(6	)
Fair value of contracts outstanding at end of period, net	$	1		$	18		$	(256	)	$	8		$	231
Nine Months Ended September 30, 2011
Fair value of contracts at beginning of period, net	$	(79	)	$	11		$	(493	)	$	19		$	384
Contracts realized or otherwise settled during the period		29			(7	)		207			(10	)		(161	)
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-
Fair value of new contracts entered into during the period		5			18			(7	)		(1	)		(5	)
Other changes in fair value		46			(4	)		37			-			13
Fair value of contracts outstanding at end of period, net	$	1		$	18		$	(256	)	$	8		$	231

(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 September 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	$	(11	)	$	(4	)	$	(1	)	$	-	$	(16	)
Level 2 ^(a)		2			-			-			-		2
Level 3 ^(b)		(18	)		(56	)		(8	)		97		15
Total	$	(27	)	$	(60	)	$	(9	)	$	97	$	1
Ameren Missouri:
Level 1	$	(4	)	$	(4	)	$	(1	)	$	-	$	(9	)
Level 2 ^(a)		1			-			-			-		1
Level 3 ^(b)		26			-			-			-		26
Total	$	23		$	(4	)	$	(1	)	$	-	$	18
Ameren Illinois:
Level 1	$	(6	)	$	-		$	-		$	-	$	(6	)
Level 2 ^(a)		-			-			-			-		-
Level 3 ^(b)		(233	)		(107	)		(7	)		97		(250	)
Total	$	(239	)	$	(107	)	$	(7	)	$	97	$	(256	)
Genco:
Level 1	$	-		$	-		$	-		$	-	$	-
Level 2 ^(a)		-			-			-			-		-
Level 3 ^(b)		6			2			-			-		8
Total	$	6		$	2		$	-		$	-	$	8

(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 September 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 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 April 2011 FAC prudence review order and subsequent FAC prudence review;

•

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 CO ₂ 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
July 1 - July 31, 2011		896	$	29.67	-	-
August 1 - August 31, 2011		33		29.37	-	-
September 1 - September 30, 2011		-		-	-	-
Total		929	$	29.66	-	-

(a)

Included in July were 896 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 August were 33 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 directors 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.

Ameren Missouri, Ameren Illinois and Genco did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from July 1, 2011, to September 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:
Instruments Defining Rights of Security Holders, Including Indentures
4.1	Ameren Ameren Illinois	Second Supplemental Indenture, dated as of July 21, 2011, by and between Ameren Illinois and The Bank of New York Mellon Trust Company, N.A., as trustee, supplementing the Indenture dated as of June 1, 2006 from CILCO (predecessor in interest to Ameren Illinois) and the trustee.
4.2	Ameren Ameren Illinois	Second Supplemental Indenture, dated as of July 21, 2011, by and between Ameren Illinois and The Bank of New York Mellon Trust Company, N.A., as trustee, supplementing the Indenture dated as of June 1, 2006 from IP (predecessor in interest to Ameren Illinois) and the trustee.
Statement re: Computation of Ratios
12.1	Ameren	Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.2	Ameren Missouri	Ameren Missouri’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.3	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


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
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
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 September 30, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statement of Income for the three and nine months ended September 30, 2011 and 2010, (ii) the Consolidated Balance Sheet at September 30, 2011, and December 31, 2010, (iii) the Consolidated Statement of Cash Flows for the nine months ended September 30, 2011 and 2010, and (iv) the Combined Notes to the Financial Statements for the nine months ended September 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.

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: November 8, 2011

Exhibit 4.1

SECOND SUPPLEMENTAL INDENTURE

Dated as of July 21, 2011

THIS SECOND SUPPLEMENTAL INDENTURE to the Indenture referred to below is dated as of July 21, 2011 (this “Second Supplemental Indenture”) between AMEREN ILLINOIS COMPANY, an Illinois corporation (the “Company”), and THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A. (formerly The Bank of New York Trust Company, N.A.) (the “Trustee”).

Central Illinois Light Company (“CILCO”) and the Trustee executed an Indenture, dated as of June 1, 2006 (as supplemented and amended, the “Indenture”), providing, among other things, for the issuance from time to time of CILCO’s Notes.

$54,000,000 aggregate principal amount of CILCO’s 6.20% Senior Secured Notes due 2016 and $42,000,000 aggregate principal amount of CILCO’s 6.70% Senior Secured Notes due 2036 were authenticated and delivered pursuant to the Company Order dated June 14, 2006 and remain outstanding as of the date hereof.

$150,000,000 aggregate principal amount of CILCO’s 8.875% Senior Notes due 2013 were authenticated and delivered pursuant to the Company Order dated December 9, 2008 and remain outstanding as of the date hereof.

On October 1, 2010, CILCO and Illinois Power Company were merged into the Company whereby the Company was the surviving corporation. The Indenture was supplemented by the First Supplemental Indenture, dated as of October 1, 2010, pursuant to which the Company, among other things, assumed the obligations of CILCO under the Indenture and the Notes and was substituted for CILCO under the Indenture.

Pursuant to Section 13.01 of the Indenture, the Company, when authorized by Board Resolution, and the Trustee may enter into an indenture supplemental to the Indenture for one or more of the purposes set forth in such Section 13.01 without the consent of the Holders of any of the Notes at the time outstanding, including to make such provision in regard to matters or questions arising under the Indenture as may be necessary or desirable, and not inconsistent with the Indenture or prejudicial to the interests of the holders in any material respect, for the purpose of supplying any omission, curing any ambiguity, or curing, correcting or supplementing any defective or inconsistent provision.

The Company has directed the Trustee to execute and deliver this Second Supplemental Indenture in accordance with the terms of the Indenture.

All things necessary to make this Second Supplemental Indenture the legal, valid and binding obligation of the Company have been done.

In consideration of the foregoing premises, the parties mutually agree as follows for the benefit of each other and for the equal and ratable benefit of the Holders of the Notes:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions . Except as otherwise defined herein, capitalized terms defined in the Indenture are used herein as therein defined.

ARTICLE II

AMENDMENT TO INDENTURE

Section 2.1 Amendments to Section 6.07(a) of the Indenture . On and after the date hereof, Section 6.07(a) of the Indenture shall be amended (A) by adding the following parenthetical at the end of clause (ii) of such section: “(which Liens may extend to Operating Property acquired, constructed, developed, repaired, altered or improved after such merger, consolidation, sale, lease or disposition if required by the terms of the mortgage, security agreement or other instrument creating such Lien; provided that such Liens may not extend to Operating Property owned by the Company immediately prior to such merger, consolidation, sale, lease or disposition)”; and (B) by adding the following parenthetical after the words “for any such purpose” in clause (iii) of such section: “(including the costs of incurring such Debt)”.

Section 2.2 Receipt by Trustee . In accordance with Section 13.05 of the Indenture, the parties acknowledge that the Trustee has received an Officers’ Certificate and an Opinion of Counsel as conclusive evidence that this Second Supplemental Indenture complies with the requirements of Article XIII of the Indenture.

ARTICLE III

MISCELLANEOUS

Section 3.1 Parties . Nothing expressed or mentioned herein is intended or shall be construed to give any Person, other than the Holders and the Trustee, any legal or equitable right, remedy or claim under or in respect of this Second Supplemental Indenture or the Indenture or any provision herein or therein contained.

Section 3.2 Governing Law . This Second Supplemental Indenture shall be governed by and deemed to be a contract under, and construed in accordance with, the laws of the State of New York, and for all purposes shall be construed in accordance with the laws of said State without regard to conflicts of law principles thereof.

Section 3.3 Ratification of Indenture; Second Supplemental Indenture Part of Indenture . Except as expressly supplemented hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions, and provisions thereof shall remain in full force and effect. This Second Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notes heretofore or hereafter authenticated and delivered shall be bound hereby. The Trustee makes no representation or warranty as to the validity or sufficiency of this Second Supplemental Indenture.

Section 3.4 Multiple Originals . The parties may sign any number of copies of this Second Supplemental Indenture. Each signed copy shall be an original, but all of them shall represent the same agreement.

Section 3.5 Headings . The headings of the Articles and Sections of this Second Supplemental Indenture have been inserted for convenience of reference only, are not intended to be considered a part hereof and shall not modify or restrict any of the terms or provisions hereof.

Section 3.6 Trustee . The Trustee makes no representations as to the validity or sufficiency of this Second Supplemental Indenture. The recitals and statements herein are deemed to be those of the Company and not of the Trustee.

[Rest of page intentionally left blank]

IN WITNESS WHEREOF, the parties hereto have caused this Second Supplemental Indenture to be duly executed as of the date first written above.


Ameren Illinois Company

By:	/s/ Jerre E. Birdsong
	Name:	Jerre E. Birdsong
	Title:	Vice President and Treasurer

The Bank of New York Mellon Trust Company, N.A.,
	as Trustee

By:	/s/ Kent Schroeder
	Name:	Kent Schroeder
	Title:	Vice President

Exhibit 4.2

SECOND SUPPLEMENTAL INDENTURE

Dated as of July 21, 2011

Illinois Power Company (“IP”) and the Trustee executed an Indenture, dated as of June 1, 2006 (as supplemented and amended, the “Indenture”), providing, among other things, for the issuance from time to time of IP’s Notes.

$75,000,000 aggregate principal amount of IP’s 6.25% Senior Secured Notes due 2016 were authenticated and delivered pursuant to the Company Order dated June 14, 2006 and remain outstanding as of the date hereof.

$250,000,000 aggregate principal amount of IP’s 6.125% Senior Notes due 2017 were authenticated and delivered pursuant to the Company Order dated November 20, 2007 and remain outstanding as of the date hereof.

$337,000,000 aggregate principal amount of IP’s 6.25% Senior Notes due 2018 were authenticated and delivered pursuant to the Company Order dated April 8, 2008 and remain outstanding as of the date hereof.

$400,000,000 aggregate principal amount of IP’s 9.75% Senior Notes due 2018 were authenticated and delivered pursuant to the Company Order dated October 23, 2008 and remain outstanding as of the date hereof.

On October 1, 2010, Central Illinois Light Company and IP were merged into the Company whereby the Company was the surviving corporation. The Indenture was supplemented by the First Supplemental Indenture, dated as of October 1, 2010, pursuant to which the Company, among other things, assumed the obligations of IP under the Indenture and the Notes and was substituted for IP under the Indenture.

$60,000,000 aggregate principal amount of the Company’s Senior Notes Series CIPS-AA, $150,000,000 aggregate principal amount of the Company’s Senior Notes Series CIPS-BB, and $61,500,000 aggregate principal amount of the Company’s Senior Notes Series CIPS-CC were authenticated and delivered pursuant to the Company Order dated October 1, 2010 and remain outstanding as of the date hereof.

The Company has directed the Trustee to execute and deliver this Second Supplemental Indenture in accordance with the terms of the Indenture.

All things necessary to make this Second Supplemental Indenture the legal, valid and binding obligation of the Company have been done.

In consideration of the foregoing premises, the parties mutually agree as follows for the benefit of each other and for the equal and ratable benefit of the Holders of the Notes:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions . Except as otherwise defined herein, capitalized terms defined in the Indenture are used herein as therein defined.

ARTICLE II

AMENDMENT TO INDENTURE

ARTICLE III

MISCELLANEOUS

IN WITNESS WHEREOF, the parties hereto have caused this Second Supplemental Indenture to be duly executed as of the date first written above.


Ameren Illinois Company

By:	/s/ Jerre E. Birdsong
	Name:	Jerre E. Birdsong
	Title:	Vice President and Treasurer

The Bank of New York Mellon Trust Company, N.A.,
	as Trustee

By:	/s/ M. Callahan
	Name:	M. Callahan
	Title:	Vice President

Exhibit 12.1

Ameren Corporation

Computation of Ratio of Earnings to Fixed Charges

(Thousands of Dollars, Except Ratios)


	Nine Months Ended September 30, 2011		Year Ended December 31, 2010 ^(a)
Net income from continuing operations attributable to Ameren Corporation	$	493,599	$	138,678
Add- Net income attributable to noncontrolling interest		1,542		3,366
Add- Taxes based on income		292,894		325,320


Net income before income taxes and noncontrolling interest		788,035		467,364
Add- fixed charges:
Interest on short-term and long-term debt ^(b)		348,469		511,468
Estimated interest cost within rental expense		6,075		8,593
Amortization of net debt premium, discount, and expenses		10,056		14,337
Subsidiary preferred stock dividends		4,833		8,278
Adjust preferred stock dividends to pretax basis		2,840		4,753

Total fixed charges		372,273		547,429


Less: Adjustment of preferred stock dividends to pretax basis		2,840		4,753

Earnings available for fixed charges	$	1,157,468	$	1,010,040


Ratio of earnings to fixed charges		3.11		1.84

^(a)	In the third quarter of 2010, Ameren Corporation recorded a goodwill and other impairment charge of $589 million. See Note 17 - Goodwill and Other Asset Impairments under Part II, Item 8, of the 2010 Form 10-K for additional information.

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

Exhibit 12.2

Union Electric Company

Computation of Ratio of Earnings to Fixed Charges and Combined

Fixed Charges and Preferred Stock Dividend Requirements

(Thousands of Dollars, Except Ratios)


	Nine Months Ended September 30, 2011		Year Ended December 31, 2010
Net income from continuing operations	$	303,803	$	368,702
Add- Taxes based on income		166,069		199,085


Net income before income taxes		469,872		567,787
Add- fixed charges:
Interest on short-term and long-term debt ^(a)		168,601		232,157
Estimated interest cost within rental expense		2,646		3,689
Amortization of net debt premium, discount, and expenses		4,808		6,744


Total fixed charges		176,055		242,590


Earnings available for fixed charges		645,927		810,377


Ratio of earnings to fixed charges		3.67		3.34


Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends		2,565		4,716
Adjustment to pretax basis		1,402		2,546

		3,967		7,262


Combined fixed charges and preferred stock dividend requirements	$	180,022	$	249,852


Ratio of earnings to combined fixed charges and preferred stock dividend requirements		3.59		3.24

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

Exhibit 12.3

Ameren Illinois Company

Computation of Ratio of Earnings to Fixed Charges and Combined

Fixed Charges and Preferred Stock Dividend Requirements

(Thousands of Dollars, Except Ratios)


	Nine Months Ended September 30, 2011		Year Ended December 31, 2010
Net income from continuing operations	$	170,019	$	212,547
Add- Taxes based on income		111,264		136,614


Net income before income taxes		281,283		349,161
Add- fixed charges:
Interest on short-term and long-term debt ^(a)		100,188		152,667
Estimated interest cost within rental expense		2,717		3,899
Amortization of net debt premium, discount, and expenses		3,947		5,250


Total fixed charges		106,852		161,816


Earnings available for fixed charges		388,135		510,977


Ratio of earnings to fixed charges		3.63		3.15


Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends		2,267		4,435
Adjustment to pretax basis		1,484		2,396

		3,751		6,831


Combined fixed charges and preferred stock dividend requirements	$	110,603	$	168,647

Ratio of earnings to combined fixed charges and preferred stock dividend requirements		3.51		3.02

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

Exhibit 12.4

Ameren Energy Generating Company

Computation of Ratio of Earnings to Fixed Charges

(Thousands of Dollars, Except Ratios)


	Nine Months Ended September 30, 2011		Year Ended December 31, 2010
Net income (loss) from continuing operations attributable to Ameren Energy Generating Company	$	28,738	$	(38,573)
Add- Net income attributable to noncontrolling interest		1,542		3,366
Add- Taxes based on income		24,335		19,422


Net income (loss) before income taxes and noncontrolling interest		54,615		(15,785)
Add- fixed charges:
Interest on short-term and long-term debt ^(a)		46,533		76,321
Estimated interest cost within rental expense		217		295
Amortization of net debt premium, discount, and expenses		506		1,026


Total fixed charges		47,256		77,642


Earnings available for fixed charges	$	101,871	$	61,857


Ratio of earnings to fixed charges		2.16		- ^(b)

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

^(b)

Earnings are inadequate to cover fixed charges by $15.8 million for the year ended December 31, 2010. In the third quarter of 2010, Ameren Energy Generating Company recorded a goodwill and other impairment charge of $170 million. See Note 17 - Goodwill and Other Asset Impairments under Part II, Item 8, of the 2010 Form 10-K for additional information.

Exhibit 31.1

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

OF PRINCIPAL EXECUTIVE OFFICER OF AMEREN CORPORATION

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

I, Thomas R. Voss, certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended September 30, 2011 of Ameren Corporation;

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

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

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

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

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

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

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

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

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

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

Date: November 8, 2011

/s/ Thomas R. Voss

Thomas R. Voss

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

Exhibit 31.2

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

OF PRINCIPAL FINANCIAL OFFICER OF AMEREN CORPORATION

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

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

1. I have reviewed this report on Form 10-Q for the quarterly period ended September 30, 2011 of Ameren Corporation;

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

Date: November 8, 2011

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 31.3

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

OF PRINCIPAL EXECUTIVE OFFICER OF UNION ELECTRIC COMPANY

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

I, Warner L. Baxter, certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended September 30, 2011 of Union Electric Company;

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

Date: November 8, 2011

/s/ Warner L. Baxter

Warner L. Baxter

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

Exhibit 31.4

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

OF PRINCIPAL FINANCIAL OFFICER OF UNION ELECTRIC COMPANY

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

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

1. I have reviewed this report on Form 10-Q for the quarterly period ended September 30, 2011 of Union Electric Company;

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

Date: November 8, 2011

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 31.5

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

OF PRINCIPAL EXECUTIVE OFFICER OF AMEREN ILLINOIS COMPANY

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

I, Scott A. Cisel, certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended September 30, 2011 of Ameren Illinois Company;

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

Date: November 8, 2011

/s/ Scott A. Cisel

Scott A. Cisel

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

Exhibit 31.6

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

OF PRINCIPAL FINANCIAL OFFICER OF AMEREN ILLINOIS COMPANY

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

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

1. I have reviewed this report on Form 10-Q for the quarterly period ended September 30, 2011 of Ameren Illinois Company;

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

Date: November 8, 2011

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 31.7

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

OF PRINCIPAL EXECUTIVE OFFICER OF

AMEREN ENERGY GENERATING COMPANY

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

I, Steven R. Sullivan, certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended September 30, 2011 of Ameren Energy Generating Company;

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

Date: November 8, 2011

/s/ Steven R. Sullivan

Steven R. Sullivan

Chairman and President

(Principal Executive Officer)

Exhibit 31.8

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

OF PRINCIPAL FINANCIAL OFFICER OF AMEREN ENERGY GENERATING COMPANY

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

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

1. I have reviewed this report on Form 10-Q for the quarterly period ended September 30, 2011 of Ameren Energy Generating Company;

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

Date: November 8, 2011

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 32.1

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

AMEREN CORPORATION

(required by Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-Q for the quarterly period ended September 30, 2011 of Ameren Corporation (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: November 8, 2011

/s/ Thomas R. Voss

Thomas R. Voss

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

Exhibit 32.2

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

UNION ELECTRIC COMPANY

(required by Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-Q for the quarterly period ended September 30, 2011 of Union Electric Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: November 8, 2011

/s/ Warner L. Baxter

Warner L. Baxter

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

Exhibit 32.3

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

AMEREN ILLINOIS COMPANY

(required by Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-Q for the quarterly period ended September 30, 2011 of Ameren Illinois Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: November 8, 2011

/s/ Scott A. Cisel

Scott A. Cisel

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

Exhibit 32.4

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

AMEREN ENERGY GENERATING COMPANY

(required by Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-Q for the quarterly period ended September 30, 2011 of Ameren Energy Generating Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: November 8, 2011

/s/ Steven R. Sullivan

Steven R. Sullivan

Chairman and President

(Principal Executive Officer)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)