Ameren Illinois (AILIN) 10-Q 2012 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

for the Quarterly Period Ended September 30, 2012

OR

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

for the transition period from             to             .

Commission File Number	Exact name of registrant as specified in its charter; State of Incorporation; Address and Telephone Number	IRS Employer Identification No.
1-14756	Ameren Corporation	43-1723446
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222
1-2967	Union Electric Company	43-0559760
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222
1-3672	Ameren Illinois Company	37-0211380
	(Illinois Corporation)
	300 Liberty Street
	Peoria, Illinois 61602
	(309) 677-5271
333-56594	Ameren Energy Generating Company	37-1395586
	(Illinois Corporation)
	1500 Eastport Plaza Drive
	Collinsville, Illinois 62234
	(618) 343-7777

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

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

(a) Ameren Energy Generating Company is not required to file reports under the Securities Exchange Act of 1934. However, Ameren Energy Generating Company has filed all Exchange Act reports for the preceding 12 months.

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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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

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

	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 Exchange Act).

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

The number of shares outstanding of each registrant’s classes of common stock as of October 31, 2012, was as follows:

Ameren Corporation	Common stock, $0.01 par value per share - 242,634,671
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 Statement of Comprehensive Income		6
	Consolidated Balance Sheet		7
	Consolidated Statement of Cash Flows		8
	Union Electric Company
	Statement of Income and Comprehensive Income		9
	Balance Sheet		10
	Statement of Cash Flows		11
	Ameren Illinois Company
	Statement of Income and Comprehensive Income		12
	Balance Sheet		13
	Statement of Cash Flows		14
	Ameren Energy Generating Company
	Consolidated Statement of Income (Loss) and Comprehensive Income (Loss)		15
	Consolidated Balance Sheet		16
	Consolidated Statement of Cash Flows		17
	Combined Notes to Financial Statements		18
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		64
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		94
Item 4.	Controls and Procedures		98
PART II Other Information
Item 1.	Legal Proceedings		98
Item 1A.	Risk Factors		99
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		99
Item 6.	Exhibits		100
Signatures			102

This Form 10-Q contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors included on pages 3 and 4 of this Form 10-Q under the heading “Forward-looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.

2

GLOSSARY OF TERMS AND ABBREVIATIONS

We use the words “our,” “we” or “us” with respect to certain information that relates to the individual registrants within the Ameren Corporation consolidated group. When appropriate, subsidiaries of Ameren Corporation are named specifically as their various business activities are discussed. Refer to the 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. Ameren Illinois is also defined as a financial reporting segment consisting of Ameren Illinois’ rate-regulated businesses.

COL - Nuclear energy center combined construction and operating license.

Entergy - Entergy Arkansas, Inc.

Form 10-K - The combined Annual Report on Form 10-K for the year ended December 31, 2011, filed by the Ameren Companies with the SEC.

Megawatthour or MWh - One thousand kilowatthours.

MPS - Multi-Pollutant Standard, a compliance alternative within Illinois law covering reductions in emissions of SO_2,NO_x, and mercury, which Genco, EEI, and AERG elected in 2006.

Westinghouse - Westinghouse Electric Company.

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 Ameren Missouri’s and Ameren Illinois’ electric rate cases filed in 2012; Ameren Missouri’s FAC prudence review and the related request for an accounting authority order; Ameren Illinois’ request for rehearing of a July 2012 FERC order regarding the inclusion of acquisition premiums in Ameren Illinois transmission rates; and future regulatory, judicial, or legislative actions that seek to change regulatory recovery mechanisms, such as the IEIMA, which provides for formula ratemaking in Illinois;

• the effect of Ameren Illinois participating in a new performance-based formula ratemaking process under the IEIMA, the related financial commitments required by the IEIMA and the resulting uncertain impact on the financial condition, results of operations and liquidity of Ameren Illinois;

• impairments of goodwill, intangible assets, or long-lived assets, including the Merchant Generation segment and Genco energy centers, which had carrying values that exceeded their estimated fair values by an amount significantly in excess of $1 billion after the impairment of the Duck Creek energy center in the first quarter of 2012;

• 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;

• 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;

• 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;

• the development of a multiyear capacity market within MISO and the outcomes of MISO’s inaugural annual capacity auction in 2013;

3

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

• disruptions of the capital markets, deterioration in credit metrics of the Ameren Companies, 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, including the impacts of droughts which may cause lower river levels and could limit our energy centers’ ability to generate power;

• the impact of system outages;

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

• the effects of our increasing investment in electric transmission projects and uncertainty as to whether we will achieve our expected returns in a timely fashion, if at all;

• 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 the investments it made in connection with a proposed second unit at its Callaway energy center;

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

• the effects of strategic initiatives, including mergers, acquisitions and divestitures, and any related tax implications;

• the impact of current environmental regulations on utilities and power generating companies and new, more stringent or changing requirements, including those related to greenhouse gases, other emissions, cooling water intake structures, CCR, and energy efficiency, that are enacted over time and that 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, workforce 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, cybersecurity attacks or intentionally disruptive acts.

Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.

4

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF INCOME

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

	Three Months Ended       September 30,				Nine Months Ended       September 30,
	2012		2011		2012		2011
Operating Revenues:
Electric	$	1,871	$	2,138	$	4,694	$	5,222
Gas		130		130		625		731
Total operating revenues		2,001		2,268		5,319		5,953
Operating Expenses:
Fuel		359		467		1,032		1,217
Purchased power		236		332		532		796
Gas purchased for resale		40		46		304		413
Other operations and maintenance		424		432		1,309		1,368
Asset impairments and other charges		-		124		628		126
Depreciation and amortization		188		196		582		585
Taxes other than income taxes		119		121		356		355
Total operating expenses		1,366		1,718		4,743		4,860
Operating Income		635		550		576		1,093
Other Income and Expenses:
Miscellaneous income		17		18		54		51
Miscellaneous expense		7		5		29		15
Total other income		10		13		25		36
Interest Charges		113		113		338		336
Income Before Income Taxes		532		450		263		793
Income Taxes		158		163		82		293
Net Income		374		287		181		500
Less: Net Income (Loss) Attributable to Noncontrolling Interests		-		2		(1)		6
Net Income Attributable to Ameren Corporation	$	374	$	285	$	182	$	494
Earnings per Common Share – Basic and Diluted	$	1.54	$	1.18	$	0.75	$	2.05
Dividends per Common Share	$	0.40	$	0.385	$	1.20	$	1.155
Average Common Shares Outstanding		242.6		241.7		242.6		241.2

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

5

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Unaudited) (In millions)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Net Income	$	374	$	287	$	181	$	500
Other Comprehensive Income (Loss), Net of Taxes:
Unrealized net gain (loss) on derivative hedging instruments, net of income taxes (benefit) of $2, $(2), $11, and $(6), respectively		3		(2)		17		(8)
Reclassification adjustments for derivative (gains) losses included in net income, net of income taxes (benefit) of $3, $1, $1, and $(1), respectively		(5)		(1)		(1)		2
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $30, $-, $31, and $(2), respectively		43		(1)		45		(2)
Total other comprehensive income (loss), net of taxes		41		(4)		61		(8)
Comprehensive Income		415		283		242		492
Less: Comprehensive Income Attributable to Noncontrolling Interests		9		2		8		6
Comprehensive Income Attributable to Ameren Corporation	$	406	$	281	$	234	$	486

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

6

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

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

	September 30, 2012		December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	298	$	255
Accounts receivable – trade (less allowance for doubtful accounts of $24 and $20, respectively)		523		473
Unbilled revenue		265		324
Miscellaneous accounts and notes receivable		82		69
Materials and supplies		756		712
Mark-to-market derivative assets		134		115
Current regulatory assets		250		215
Other current assets		98		132
Total current assets		2,406		2,295
Property and Plant, Net		17,833		18,127
Investments and Other Assets:
Nuclear decommissioning trust fund		407		357
Goodwill		411		411
Intangible assets		14		7
Regulatory assets		1,655		1,603
Other assets		772		845
Total investments and other assets		3,259		3,223
TOTAL ASSETS	$	23,498	$	23,645
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	206	$	179
Short-term debt		5		148
Accounts and wages payable		458		693
Taxes accrued		163		65
Interest accrued		145		101
Customer deposits		96		98
Mark-to-market derivative liabilities		155		161
Current regulatory liabilities		125		133
Other current liabilities		193		207
Total current liabilities		1,546		1,785
Long-term Debt, Net		6,781		6,677
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		3,385		3,315
Accumulated deferred investment tax credits		74		79
Regulatory liabilities		1,542		1,502
Asset retirement obligations		429		428
Pension and other postretirement benefits		1,152		1,344
Other deferred credits and liabilities		563		447
Total deferred credits and other liabilities		7,145		7,115
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 242.6		2		2
Other paid-in capital, principally premium on common stock		5,611		5,598
Retained earnings		2,259		2,369
Accumulated other comprehensive gain (loss)		2		(50)
Total Ameren Corporation stockholders’ equity		7,874		7,919
Noncontrolling Interests		152		149
Total equity		8,026		8,068
TOTAL LIABILITIES AND EQUITY	$	23,498	$	23,645

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

7

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Nine Months Ended     September 30,
	2012		2011
Cash Flows From Operating Activities:
Net income	$	181	$	500
Adjustments to reconcile net income to net cash provided by operating activities:
Loss on asset impairments and other charges		628		126
Net gain on sales of properties		(11)		(12)
Net mark-to-market loss on derivatives		6		15
Depreciation and amortization		552		558
Amortization of nuclear fuel		63		51
Amortization of debt issuance costs and premium/discounts		17		17
Deferred income taxes and investment tax credits, net		40		302
Allowance for equity funds used during construction		(26)		(25)
Other		22		2
Changes in assets and liabilities:
Receivables		(19)		130
Materials and supplies		(44)		(34)
Accounts and wages payable		(157)		(192)
Taxes accrued		97		94
Assets, other		(29)		96
Liabilities, other		137		(2)
Pension and other postretirement benefits		19		(98)
Counterparty collateral, net		23		37
Premiums paid on long-term debt repurchases		(138)		-
Net cash provided by operating activities		1,361		1,565
Cash Flows From Investing Activities:
Capital expenditures		(905)		(758)
Nuclear fuel expenditures		(56)		(45)
Purchases of securities – nuclear decommissioning trust fund		(341)		(163)
Sales of securities – nuclear decommissioning trust fund		277		147
Proceeds from sales of properties		22		50
Other		(8)		18
Net cash used in investing activities		(1,011)		(751)
Cash Flows From Financing Activities:
Dividends on common stock		(284)		(279)
Dividends paid to noncontrolling interest holders		(5)		(5)
Short-term debt and credit facility repayments, net		(143)		(379)
Redemptions, repurchases, and maturities of long-term debt		(754)		(150)
Issuances:
Long-term debt		882		-
Common stock		-		49
Capital issuance costs		(7)		-
Generator advances received for construction		4		-
Repayments of generator advances received for construction		-		(73)
Net cash used in financing activities		(307)		(837)
Net change in cash and cash equivalents		43		(23)
Cash and cash equivalents at beginning of year		255		545
Cash and cash equivalents at end of period	$	298	$	522
Noncash financing activity – dividends on common stock	$	(7)	$	-

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

8

UNION ELECTRIC COMPANY

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Operating Revenues:
Electric	$	1,046	$	1,099	$	2,504	$	2,592
Gas		18		16		94		113
Other		-		-		1		4
Total operating revenues		1,064		1,115		2,599		2,709
Operating Expenses:
Fuel		192		249		549		682
Purchased power		37		35		57		81
Gas purchased for resale		5		4		42		55
Other operations and maintenance		203		218		611		682
Loss from regulatory disallowance		-		89		-		89
Depreciation and amortization		111		102		328		300
Taxes other than income taxes		87		85		236		234
Total operating expenses		635		782		1,823		2,123
Operating Income		429		333		776		586
Other Income and Expenses:
Miscellaneous income		15		16		48		45
Miscellaneous expense		4		2		11		8
Total other income		11		14		37		37
Interest Charges		55		54		167		153
Income Before Income Taxes		385		293		646		470
Income Taxes		148		102		243		166
Net Income		237		191		403		304
Other Comprehensive Income		-		-		-		-
Comprehensive Income	$	237	$	191	$	403	$	304
Net Income	$	237	$	191	$	403	$	304
Preferred Stock Dividends		1		1		3		3
Net Income Available to Common Stockholder	$	236	$	190	$	400	$	301

The accompanying notes as they relate to Union Electric Company are an integral part of these financial statements.

9

UNION ELECTRIC COMPANY

BALANCE SHEET

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

	September 30, 2012		December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	132	$	201
Accounts receivable – trade (less allowance for doubtful accounts of $8 and $7, respectively)		263		212
Accounts receivable – affiliates		3		1
Unbilled revenue		127		139
Miscellaneous accounts and notes receivable		54		42
Materials and supplies		402		348
Current regulatory assets		147		109
Other current assets		63		82
Total current assets		1,191		1,134
Property and Plant, Net		10,092		9,958
Investments and Other Assets:
Nuclear decommissioning trust fund		407		357
Intangible assets		12		7
Regulatory assets		813		855
Other assets		452		446
Total investments and other assets		1,684		1,665
TOTAL ASSETS	$	12,967	$	12,757
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	205	$	178
Accounts and wages payable		187		414
Accounts payable – affiliates		54		73
Taxes accrued		133		74
Interest accrued		68		62
Current regulatory liabilities		34		57
Other current liabilities		114		84
Total current liabilities		795		942
Long-term Debt, Net		3,806		3,772
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		2,322		2,132
Accumulated deferred investment tax credits		66		70
Regulatory liabilities		906		836
Asset retirement obligations		342		328
Pension and other postretirement benefits		432		491
Other deferred credits and liabilities		161		149
Total deferred credits and other liabilities		4,229		4,006
Commitments and Contingencies (Notes 2, 8, 9 and 10)
Stockholders’ Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding		511		511
Other paid-in capital, principally premium on common stock		1,555		1,555
Preferred stock not subject to mandatory redemption		80		80
Retained earnings		1,991		1,891
Total stockholders’ equity		4,137		4,037
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	12,967	$	12,757

The accompanying notes as they relate to Union Electric Company are an integral part of these financial statements.

10

UNION ELECTRIC COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Nine Months Ended September 30,
	2012		2011
Cash Flows From Operating Activities:
Net income	$	403	$	304
Adjustments to reconcile net income to net cash provided by operating activities:
Loss from regulatory disallowance		-		89
Depreciation and amortization		303		278
Amortization of nuclear fuel		63		51
Amortization of debt issuance costs and premium/discounts		5		5
Deferred income taxes and investment tax credits, net		217		203
Allowance for equity funds used during construction		(23)		(22)
Other		7		(5)
Changes in assets and liabilities:
Receivables		(62)		(46)
Materials and supplies		(53)		2
Accounts and wages payable		(168)		(143)
Taxes accrued		59		51
Assets, other		(29)		82
Liabilities, other		71		3
Pension and other postretirement benefits		17		2
Premiums paid on long-term debt repurchases		(62)		-
Net cash provided by operating activities		748		854
Cash Flows From Investing Activities:
Capital expenditures		(445)		(402)
Nuclear fuel expenditures		(56)		(45)
Purchases of securities – nuclear decommissioning trust fund		(341)		(163)
Sales of securities – nuclear decommissioning trust fund		277		147
Other		(5)		4
Net cash used in investing activities		(570)		(459)
Cash Flows From Financing Activities:
Dividends on common stock		(300)		(219)
Dividends on preferred stock		(3)		(3)
Redemptions, repurchases, and maturities of long-term debt		(422)		-
Issuances of long-term debt		482		-
Capital issuance costs		(4)		-
Repayments of generator advances received for construction		-		(19)
Net cash used in financing activities		(247)		(241)
Net change in cash and cash equivalents		(69)		154
Cash and cash equivalents at beginning of year		201		202
Cash and cash equivalents at end of period	$	132	$	356

The accompanying notes as they relate to Union Electric Company are an integral part of these financial statements.

11

AMEREN ILLINOIS COMPANY

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Operating Revenues:
Electric	$	536	$	631	$	1,404	$	1,556
Gas		112		114		532		619
Other		-		-		-		1
Total operating revenues		648		745		1,936		2,176
Operating Expenses:
Purchased power		224		270		576		677
Gas purchased for resale		35		43		262		358
Other operations and maintenance		159		152		513		501
Depreciation and amortization		55		55		165		161
Taxes other than income taxes		24		29		94		96
Total operating expenses		497		549		1,610		1,793
Operating Income		151		196		326		383
Other Income and Expenses:
Miscellaneous income		2		2		5		5
Miscellaneous expense		2		2		15		4
Total other income (expense)		-		-		(10)		1
Interest Charges		34		33		98		103
Income Before Income Taxes		117		163		218		281
Income Taxes		46		65		86		111
Net Income		71		98		132		170
Other Comprehensive Loss, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(1), $(1), $(2) and $(2), respectively		(1)		(1)		(3)		(3)
Comprehensive Income	$	70	$	97	$	129	$	167
Net Income	$	71	$	98	$	132	$	170
Preferred Stock Dividends		-		-		2		2
Net Income Available to Common Stockholder	$	71	$	98	$	130	$	168

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

12

AMEREN ILLINOIS COMPANY

BALANCE SHEET

(Unaudited) (In millions)

	September 30, 2012		December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	93	$	21
Accounts receivable – trade (less allowance for doubtful accounts of $17 and $13, respectively)		197		201
Accounts receivable – affiliates		9		15
Unbilled revenue		108		146
Miscellaneous accounts receivable		11		6
Materials and supplies		202		199
Current regulatory assets		161		306
Current accumulated deferred income taxes, net		46		58
Other current assets		47		65
Total current assets		874		1,017
Property and Plant, Net		4,948		4,770
Investments and Other Assets:
Tax receivable – Genco		40		56
Goodwill		411		411
Regulatory assets		842		748
Other assets		112		211
Total investments and other assets		1,405		1,426
TOTAL ASSETS	$	7,227	$	7,213
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	1	$	1
Accounts and wages payable		148		133
Accounts payable – affiliates		82		103
Taxes accrued		12		15
Interest accrued		37		22
Customer deposits		74		76
Mark-to-market derivative liabilities		78		99
Mark-to-market derivative liabilities – affiliates		59		200
Environmental remediation		38		63
Current regulatory liabilities		91		76
Other current liabilities		62		70
Total current liabilities		682		858
Long-term Debt, Net		1,727		1,657
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,009		895
Accumulated deferred investment tax credits		6		7
Regulatory liabilities		636		666
Pension and other postretirement benefits		444		495
Other deferred credits and liabilities		276		183
Total deferred credits and other liabilities		2,371		2,246
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		1,965		1,965
Preferred stock not subject to mandatory redemption		62		62
Retained earnings		406		408
Accumulated other comprehensive income		14		17
Total stockholders’ equity		2,447		2,452
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	7,227	$	7,213

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

13

AMEREN ILLINOIS COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Nine Months Ended September 30,
	2012		2011
Cash Flows From Operating Activities:
Net income	$	132	$	170
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		159		154
Amortization of debt issuance costs and premium/discounts		7		6
Deferred income taxes and investment tax credits, net		127		137
Other		(8)		(7)
Changes in assets and liabilities:
Receivables		58		169
Materials and supplies		(6)		(41)
Accounts and wages payable		(4)		(58)
Taxes accrued		(3)		(14)
Assets, other		(2)		3
Liabilities, other		42		(13)
Pension and other postretirement benefits		(8)		(98)
Counterparty collateral, net		23		29
Premiums paid on long-term debt repurchases		(76)		-
Net cash provided by operating activities		441		437
Cash Flows From Investing Activities:
Capital expenditures		(309)		(261)
Returns of advances from ATXI for construction		-		49
Other		5		6
Net cash used in investing activities		(304)		(206)
Cash Flows From Financing Activities:
Dividends on common stock		(132)		(238)
Dividends on preferred stock		(2)		(2)
Redemptions, repurchases, and maturities of long-term debt		(332)		(150)
Issuances of long-term debt		400		-
Capital issuance costs		(3)		-
Generator advances received for construction		4		-
Repayments of generator advances received for construction		-		(53)
Capital contribution from parent		-		6
Net cash used in financing activities		(65)		(437)
Net change in cash and cash equivalents		72		(206)
Cash and cash equivalents at beginning of year		21		322
Cash and cash equivalents at end of period	$	93	$	116

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

14

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

(Unaudited) (In millions)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Operating Revenues	$	218	$	327	$	606	$	828
Operating Expenses:
Fuel		122		169		352		410
Purchased power		1		37		1		55
Other operations and maintenance		41		48		133		137
Asset impairments and other charges		-		35		-		36
Depreciation and amortization		15		24		61		73
Taxes other than income taxes		5		4		16		16
Total operating expenses		184		317		563		727
Operating Income		34		10		43		101
Other Income and Expenses:
Miscellaneous income		1		1		1		1
Miscellaneous expense		1		-		1		-
Total other income		-		1		-		1
Interest Charges		14		16		40		47
Income (Loss) Before Income Taxes		20		(5)		3		55
Income Taxes (Benefit)		9		(1)		1		24
Net Income (Loss)		11		(4)		2		31
Less: Net Income (Loss) Attributable to Noncontrolling Interest		(2)		1		(6)		2
Net Income (Loss) Attributable to Ameren Energy Generating Company	$	13	$	(5)	$	8	$	29
Net Income (Loss)	$	11	$	(4)	$	2	$	31
Other Comprehensive Income, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income taxes of $30, $-, $33 and $1, respectively		43		1		48		2
Total other comprehensive income, net of taxes		43		1		48		2
Comprehensive Income (Loss)		54		(3)		50		33
Less: Comprehensive Income Attributable to Noncontrolling Interest		7		1		3		2
Comprehensive Income (Loss) Attributable to Ameren Energy Generating Company	$	47	$	(4)	$	47	$	31

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

15

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions, except shares)

	September 30, 2012		December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	25	$	8
Advances to money pool		32		74
Accounts receivable – affiliates		62		89
Miscellaneous accounts receivable		15		13
Materials and supplies		117		122
Other current assets		23		19
Total current assets		274		325
Property and Plant, Net		2,288		2,231
Other assets		13		16
TOTAL ASSETS	$	2,575	$	2,572
LIABILITIES AND EQUITY
Current Liabilities:
Accounts and wages payable	$	62	$	71
Accounts payable – affiliates		11		13
Current portion of tax payable – Ameren Illinois		6		8
Taxes accrued		13		20
Interest accrued		27		13
Mark-to-market derivative liabilities		9		3
Other current liabilities		10		14
Total current liabilities		138		142
Long-term Debt, Net		824		824
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		350		304
Accumulated deferred investment tax credits		2		2
Tax payable – Ameren Illinois		40		56
Asset retirement obligations		59		66
Pension and other postretirement benefits		66		141
Other deferred credits and liabilities		18		12
Total deferred credits and other liabilities		535		581
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		656		653
Retained earnings		445		437
Accumulated other comprehensive loss		(33)		(72)
Total Ameren Energy Generating Company stockholder’s equity		1,068		1,018
Noncontrolling Interest		10		7
Total equity		1,078		1,025
TOTAL LIABILITIES AND EQUITY	$	2,575	$	2,572

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

16

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Nine Months Ended September 30,
	2012		2011
Cash Flows From Operating Activities:
Net income	$	2	$	31
Adjustments to reconcile net income to net cash provided by operating activities:
Loss on asset impairments and other charges		-		36
(Gain) loss on sales of properties		1		(12)
Net mark-to-market loss on derivatives		10		5
Depreciation and amortization		61		75
Amortization of debt issuance costs and premium/discounts		2		2
Deferred income taxes and investment tax credits, net		12		45
Other		8		-
Changes in assets and liabilities:
Receivables		22		22
Materials and supplies		7		6
Accounts and wages payable		-		(16)
Taxes accrued		(7)		(6)
Assets, other		(3)		3
Liabilities, other		(7)		(9)
Pension and other postretirement benefits		3		(3)
Net cash provided by operating activities		111		179
Cash Flows From Investing Activities:
Capital expenditures		(140)		(112)
Proceeds from sales of properties		4		49
Money pool advances, net		42		(38)
Net cash used in investing activities		(94)		(101)
Cash Flows From Financing Activities:
Credit facility repayments, net		-		(100)
Capital contribution from parent		-		24
Net cash used in financing activities		-		(76)
Net change in cash and cash equivalents		17		2
Cash and cash equivalents at beginning of year		8		6
Cash and cash equivalents at end of period	$	25	$	8

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

17

AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY

AMEREN ILLINOIS COMPANY

AMEREN ENERGY GENERATING COMPANY (Consolidated)

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

September 30, 2012

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. 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.

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

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

• AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company. Genco operates a merchant electric generation business in Illinois and holds an 80% ownership interest in EEI, which it consolidates for financial reporting purposes.

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

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

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

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three months and nine months ended September 30, 2012, and 2011. The number of dilutive restricted stock shares and performance share units had an immaterial impact on earnings per share.

Stock-based Compensation

The fair value of each share unit awarded in January 2012 under the 2006 Plan was determined to be $35.68. That amount was based on Ameren’s closing common share price of $33.13 at December 31, 2011, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2012. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.41%, volatility of 17% to 31% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.

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, 2012, Ameren’s and Ameren Illinois’ goodwill related to Ameren’s acquisition of IP in 2004 and CILCORP in 2003. We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events or changes in circumstances indicate that the asset might be impaired.

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

18

At September 30, 2012, Ameren’s and Ameren Missouri’s intangible assets consisted of 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 was $14 million and $12 million, respectively, at September 30, 2012. The book value of each of Ameren’s, Ameren Missouri’s, and Genco’s CAIR emission allowances was immaterial at September 30, 2012.

Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. The following table presents amortization expense based on usage of renewable energy credits and emission allowances, net of gains from sales, for Ameren, Ameren Missouri, Ameren Illinois, and Genco during the three and nine months ended September 30, 2012, and 2011. Amortization expense based on Ameren Missouri’s usage of renewable energy credits is expensed up to $1 million annually beginning in August each year in accordance with MoPSC’s 2011 electric rate order, and the remainder is deferred as a regulatory asset pending recovery from customers through rates. The following table does not include the 2011 intangible asset impairment charges referenced below.

	Three Months				Nine Months
	2012		2011		2012		2011
Ameren Missouri	$	1	$	1	$	1	$	1
Ameren Illinois		1		2		1		3
Genco		(a)		(a)		(a)		2
Other(b)		2		-		2		1
Ameren	$	4	$	3	$	4	$	7

(a) Less than $1 million.

(b) Consists of renewable energy credit expense for Marketing Company and emission allowance expense for AERG.

During the second quarter of 2011, Ameren and Genco recorded a noncash pretax impairment charge of their emission allowances of $2 million and $1 million, respectively. Ameren Missouri recorded a $1 million impairment of its SO₂ emission allowances by reducing a previously established regulatory liability relating to the SO₂emission allowances, which had no impact on earnings. The impairment was triggered by a significant observable decline in the market price of SO₂and NO_x allowances used for CAIR compliance.

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and Ameren Missouri and Ameren Illinois natural gas customer bills. They are recorded gross in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” on the statement of income or the statement of income and comprehensive 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 - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” for the three and nine months ended September 30, 2012, and 2011:

	Three Months				Nine Months
	2012		2011		2012		2011
Ameren Missouri	$	46	$	47	$	111	$	110
Ameren Illinois		9		10		37		42
Ameren	$	55	$	57	$	148	$	152

Uncertain Tax Positions

The amount of unrecognized tax benefits as of September 30, 2012, was $167 million, $143 million, $11 million, and $12 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of September 30, 2012, that would impact the effective tax rate, if recognized, was $1 million, $4 million, $(1) million and $1 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

Ameren’s federal income tax returns for the years 2007 through 2010 are before the Appeals Office of the Internal Revenue Service.

19

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 expected that a settlement may be reached with the Appeals Office of the Internal Revenue Service in the next twelve months for the years 2007 through 2009 that would result in a decrease in uncertain tax liabilities. In addition, it is reasonably possible that events will occur during the next twelve 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 2012:

	Ameren Missouri(a)			Ameren Illinois(b)			Genco			AERG			Ameren(a)
Balance at December 31, 2011	$	328		$	3		$	71	(c)	$	31		$	433	(c)
Liabilities incurred		-			-			1			-			1
Liabilities settled		(1	)		(d	)		(5	)		(d	)		(6	)
Accretion in 2012(e)		14			(d	)		3			2			19
Change in estimates(f)		1			(d	)		(11	)		(d	)		(10	)
Balance at September 30, 2012	$	342		$	3		$	59		$	33		$	437	(g)

(a) The nuclear decommissioning trust fund assets of $407 million and $357 million as of September 30, 2012, and December 31, 2011, respectively, were restricted for decommissioning of the Callaway energy center.

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

(c) Balance included $5 million in “Other current liabilities” on the balance sheet as of December 31, 2011.

(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 and Genco changed their estimates for asbestos removal. The estimates for asbestos removal costs at Genco’s Hutsonville and Meredosia energy centers decreased due to less asbestos than anticipated in the energy centers’ structures discovered during reviews made after the closure of these energy centers, and more cost efficient removal than anticipated being made possible due to the closure of the energy centers. Additionally, Genco changed the estimates related to retirement costs for its coal combustion byproduct storage areas.

(g) Balance included $8 million in “Other current liabilities” on the balance sheet as of September 30, 2012.

Noncontrolling Interest

Ameren’s noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren’s subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren’s equity in its consolidated balance sheet. Genco’s noncontrolling interest comprised the 20% of EEI not owned by Genco. This noncontrolling interest was classified as a component of equity separate from Genco’s equity in its consolidated balance sheet. See Note 12 - Retirement Benefits for information regarding other comprehensive income and amendments to EEI’s benefit plans.

A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren and Genco for the three and nine months ended September 30, 2012, and 2011, is shown below:

	Three Months						Nine Months
	2012			2011			2012			2011
Ameren:
Noncontrolling interests, beginning of period	$	145		$	155		$	149		$	154
Net income (loss) attributable to noncontrolling interests		-			2			(1	)		6
Dividends paid to noncontrolling interest holders		(2	)		(2	)		(5	)		(5	)
Other comprehensive income attributable to noncontrolling interests(a)		9			-			9			-
Noncontrolling interests, end of period	$	152		$	155		$	152		$	155
Genco:
Noncontrolling interest, beginning of period	$	3		$	12		$	7		$	11
Net income (loss) attributable to noncontrolling interest		(2	)		1			(6	)		2
Other comprehensive income attributable to noncontrolling interest(a)		9			-			9			-
Noncontrolling interest, end of period	$	10		$	13		$	10		$	13

(a) Represents pension and other postretirement benefit plan activity, net of income taxes of $6, $-, $6, and $-, respectively.

20

Merchant Generation Asset Sales in 2012

In February 2012, Ameren completed the sale of its Medina Valley energy center’s net property and plant for cash proceeds of $16 million and an additional $1 million payment at the two-year anniversary date of the sale if all terms of the sale agreement are met. Ameren recognized a $10 million pretax gain during the first quarter of 2012 from this sale. In October 2012, the buyer of the Medina Valley energy center asserted that AER has not met all the terms of the sale agreement. AER is evaluating the buyer’s claim. The dollar amount of the asserted claim does not materially differ from the payment due at the two-year anniversary date of the sale. Medina Valley was included in Ameren’s Merchant Generation segment results.

In May 2012, Genco completed the sale of a building for cash proceeds of $1 million. Genco recognized a $1 million pretax loss from this sale.

In the third quarter of 2012, AERG completed various sales of land around its Duck Creek energy center for aggregate cash proceeds of $4 million. Ameren recognized a $2 million pretax gain during the third quarter of 2012 from these sales.

EEI Employee Separation

In June 2012, EEI announced that it was reducing its workforce by 44 employees, which included both management and labor union represented employees, in response to lower demand and prices for electricity. By the end of September 2012, the staff reduction was substantially complete. Ameren and Genco each recorded a $1 million pretax charge to earnings during the nine months ended September 30, 2012, related to the workforce reduction. The charge was recorded to “Other operations and maintenance” expense on Ameren’s and Genco’s consolidated statements of income, and the charge was included in the Merchant Generation segment results.

The announced employee reduction also resulted in a curtailment of EEI’s pension and postretirement benefit plans, which are separate from Ameren’s pension and postretirement benefit plans. See Note 12 - Retirement Benefits for information regarding EEI’s plan curtailment and pension plan amendments in 2012.

NOTE 2 - RATE AND REGULATORY MATTERS

Below is a summary of significant regulatory proceedings and related lawsuits. See also Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. 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 November 2011, the Missouri Court of Appeals issued a ruling that upheld the MoPSC’s January 2009 electric rate order. In March 2012, the Circuit Court of Stoddard County, Missouri released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $21 million, reducing previously recorded trade accounts receivable.

2010 Electric Rate Order

In May 2012, the Cole County Circuit Court issued a ruling that upheld the MoPSC’s May 2010 electric rate order. In May 2012, the Cole County Circuit Court released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $16 million, reducing the previously recorded trade accounts receivable.

2011 Electric Rate Order

In July 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $173 million. The MoPSC’s 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. In July 2012, the Missouri Court of Appeals, Western District, upheld the MoPSC’s July 2011 electric rate order. Ameren Missouri will not seek further appeal of the MoPSC’s order.

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Pending Electric Rate Case

In February 2012, Ameren Missouri filed a request with the MoPSC to increase its annual revenue for electric service. The currently pending request, as amended in October 2012, seeks an annual revenue increase of $323 million based on a 10.5% return on equity. The annual increase request includes $73 million related to an anticipated increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its 2011 electric rate order. The annual increase request also includes $80 million for recovery of the costs associated with energy efficiency programs under the MEEIA, which are discussed below. In this rate case, Ameren Missouri requested that the MoPSC approve the implementation of a storm cost tracking mechanism, as well as plant-in-service accounting treatment. The plant-in-service accounting proposal is designed to reduce the impact of regulatory lag on earnings and future cash flows related to assets placed in service between rate cases by both accruing a return on the assets and deferring depreciation expense from their in-service dates until those capitalized costs are included in rates.

The MoPSC staff is currently recommending an increase to Ameren Missouri’s annual revenues of $210 million based on a return on equity of 9%. The MoPSC staff opposed Ameren Missouri’s request to implement a storm cost tracking mechanism and Ameren Missouri’s plant-in-service accounting proposal. The MoPSC staff also recommended that all transmission costs currently recovered through the FAC be recovered through base rates. Other parties also made recommendations through testimony filed in this case.

Ameren Missouri has agreed to settlements of various issues, some of which have been approved by the MoPSC and some of which are still subject to approval by the MoPSC. One of the approved settlements will allow Ameren Missouri to retain the refund received in June 2012 from Entergy related to a power purchase agreement that existed prior to the implementation of the FAC, which did not impact Ameren Missouri’s pending request. See below under Federal for additional information about this refund and Ameren Missouri’s power purchase agreement with Entergy.

The MoPSC has several important issues to consider in this case. Those issues include determining the appropriate return on equity, Ameren Missouri’s request for the implementation of a storm cost tracking mechanism and plant-in-service accounting treatment, Ameren Missouri’s request for recovery of its 2011 severance costs, and whether Ameren Missouri should be able to continue to employ its existing FAC, including all of the transmission costs currently included within the FAC, at the current 95% sharing level.

A decision by the MoPSC in this proceeding is expected in December 2012, with rates becoming effective on January 2, 2013. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve or whether any rate increase that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the increase goes into effect.

MEEIA Filing

In August 2012, the MoPSC issued an order that approved a stipulation and agreement between Ameren Missouri, MoPSC staff, and other parties. The order includes megawatthour savings targets for Ameren Missouri’s energy efficiency programs as well as associated cost recovery mechanisms and incentive awards. The order provides that, beginning in 2013, Ameren Missouri will invest approximately $147 million over three years for energy efficiency programs. The order allows for Ameren Missouri to collect, over the next three years, its program costs and 90% of its projected lost revenue from customers starting on the expected effective date for the pending electric service rate case, which is expected to be January 2, 2013. The remaining 10% of projected lost revenue is expected to be recovered as part of future rate proceedings.

Additionally, the order provides for an incentive award that would allow Ameren Missouri to earn additional revenues based on achievement of certain energy efficiency goals, including approximately $19 million if 100% of its energy efficiency goals are achieved during the three-year period, with the potential to earn more if Ameren Missouri’s energy savings exceed those goals. Ameren Missouri must achieve at least 70% of its energy efficiency goals before it earns any incentive award. The recovery of the incentive award from customers, if the energy efficiency goals are achieved, would begin after the three-year energy efficiency plan is complete and upon the effective date of an electric service rate case or potentially with the future adoption of a rider mechanism.

The MoPSC’s order will not affect Ameren Missouri rates until these rates are included in an electric service rate case. The impacts of the MoPSC’s order in this MEEIA filing are expected to be included in rates set under Ameren Missouri’s pending electric service rate case that was filed in February 2012. Ameren Missouri’s pending electric service rate case includes an annual revenue increase request of $80 million related to its planned portfolio of energy efficiency programs included in its MEEIA filing.

FAC Prudence Review

Missouri law requires the MoPSC to perform prudence reviews of Ameren Missouri’s FAC at least every 18 months. In April 2011, the MoPSC issued an order with respect to its 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 because of 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 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.

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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 2012, upon appeal by Ameren Missouri, the Cole County Circuit Court reversed the MoPSC’s April 2011 order. In June 2012, the MoPSC filed an appeal of the Cole County Circuit Court’s ruling to the Missouri Court of Appeals, Western District. Ameren Missouri has not recorded additional revenues as a result of the Cole County Circuit Court’s May 2012 ruling, as the MoPSC’s appeal to the Missouri Court of Appeals is ongoing and a decision is not expected to be issued until 2013.

In February 2012, the MoPSC staff issued its FAC review report for the period from October 1, 2009, to May 31, 2011. In its report, the MoPSC staff asked 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. Missouri law does not impose a specific deadline by which the MoPSC must complete its prudence reviews. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri’s electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made. Ameren Missouri does not currently believe these amounts are probable of refund to customers.

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. If the courts ultimately rule in favor of Ameren Missouri’s position regarding the classification of the long-term partial requirements sales, Ameren Missouri would not seek to recover from customers the sum that would be covered by the accounting authority order, if it is granted.

Illinois

IEIMA

On January 3, 2012, Ameren Illinois elected to participate in the performance-based formula ratemaking process established pursuant to the IEIMA by filing initial performance-based formula rates with the ICC. The initial filing was based on 2010 recoverable costs and expected net plant additions for 2011 and 2012. In September 2012, the ICC issued an order approving an Ameren Illinois electric delivery service revenue requirement of $779 million, which is a $55 million decrease from the electric delivery service revenue requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The rates became effective on October 19, 2012, and will be effective through the end of 2012. Ameren Illinois requested a rehearing of the initial filing order, which the ICC denied. In October 2012, Ameren Illinois filed an appeal of the ICC order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013. Ameren Illinois believes that the ICC misapplied Illinois law, through including the use of an average rate base as opposed to a year-end rate base, the treatment of accumulated deferred income taxes, the method for calculating the equity portion of Ameren Illinois’ capital structure, and the method for calculating interest on the revenue requirement reconciliation.

The ICC’s September 2012 order jeopardizes Ameren Illinois’ ongoing ability to implement infrastructure improvements to the extent and on the timetable envisioned in the IEIMA. Until the uncertainty surrounding how the Illinois law will ultimately be implemented is removed, Ameren Illinois is reducing its IEIMA capital spending with a corresponding negative effect on the job creation that the legislature sought to achieve with the law. Ameren Illinois expects to reduce or defer a total of $30 million of its previously planned 2013 electric distribution capital expenditures.

On April 20, 2012, Ameren Illinois filed a request with the ICC to update its annual electric delivery service revenue requirement based on 2011 recoverable costs and expected net plant additions for 2012. The update filing will result in new electric delivery service rates on January 1, 2013. The update filing, as amended in September 2012, requested an annual revenue requirement of $796 million, which would result in an annual increase of $17 million in Ameren Illinois’ revenues for electric delivery service above the amount allowed in the ICC initial filing order. The requested increase primarily reflects higher recoverable operating expenses, higher taxes, and a higher equity portion of the capital structure offset by a lower return on equity due to decreases in the average 30-year United States treasury bond rates. In September 2012, the ICC staff recommended a $765 million electric delivery service revenue requirement, which is $14 million below the amount allowed in the ICC initial filing order. Other parties also made recommendations through testimony filed in Ameren Illinois’ update filing. On November 7, 2012, the administrative law judges issued a proposed order that reflected an annual revenue requirement of $764 million, which would result in an annual decrease of $15 million in Ameren Illinois’ revenues for electric delivery service below the amount allowed in the ICC initial filing order.

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The IEIMA provides for an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for that year. Consequently, Ameren Illinois’ 2012 electric delivery service revenues will be based on its 2012 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA’s performance-based formula ratemaking framework. The 2012 revenue requirement under the IEIMA’s formula ratemaking framework is expected to be lower than the revenue requirement included in both the ICC’s 2010 electric rate order and the ICC’s September 2012 order related to Ameren Illinois’ initial IEIMA filing. As a result, Ameren Illinois recorded a regulatory liability to represent its estimate of the probable decrease in electric delivery service rates expected to be approved by the ICC to provide Ameren Illinois recovery of all prudently and reasonably incurred costs and an earned rate of return on common equity for 2012. Ameren Illinois’ actual return on equity relating to electric delivery service cannot exceed 50 basis points above or below its allowed return. During the third quarter of 2012, Ameren Illinois’ electric delivery service return on equity was capped at the maximum allowed return on equity based on the IEIMA formula ratemaking framework. As of September 30, 2012, Ameren Illinois recorded a cumulative regulatory liability of $35 million with a corresponding decrease in electric revenues for electric delivery service relating to the 2012 revenue requirement reconciliation and the return on equity collar, which will be refunded to customers during 2014 with interest pursuant to the provisions of the IEIMA.

The IEIMA requires Ameren Illinois to obtain ICC approval of its advanced metering infrastructure deployment plan. The advanced metering infrastructure deployment plan outlines how Ameren Illinois will comply with the IEIMA requirement to spend $360 million on smart grid assets over ten years on a cost-beneficial basis to its electric customers. In March 2012, Ameren Illinois submitted its advanced metering infrastructure deployment plan to the ICC, and the ICC subsequently denied that plan in May 2012. The ICC ruled that Ameren Illinois’ plan did not provide enough support to prove that it was cost beneficial for electric customers. Ameren Illinois requested and received a rehearing from the ICC. In its rehearing request, Ameren Illinois submitted a modified advance metering infrastructure deployment plan designed to address the ICC’s concerns about the cost justification of the plan. Ameren Illinois expects the ICC will issue an order later this year. If approved, the plan targets the second quarter of 2014 to begin installation of smart meters. If an advanced metering infrastructure deployment plan is ultimately not approved by the ICC, Ameren Illinois may be precluded from using the IEIMA’s performance-based formula rates.

Federal

Electric Transmission Investment

In February 2012, FERC approved ATXI’s request for a forward-looking rate calculation with an annual reconciliation adjustment, as well as ATXI’s request for the implementation of the incentives FERC approved in its May 2011 order for the Illinois Rivers project and the Big Muddy River project.

In July 2012, Ameren, on behalf of its transmission affiliates, filed a request with FERC seeking transmission rate incentives for the Spoon River project and the Mark Twain project. Both projects have been approved by MISO. Also in that filing, Ameren requested FERC to authorize Ameren Illinois’ use of a forward-looking rate calculation with an annual reconciliation adjustment for its electric transmission projects. This forward-looking rate calculation is almost identical to the calculation FERC approved in its May 2011 order for ATXI. Ameren expects FERC to issue an order in 2012.

Ameren Missouri Power Purchase Agreement with Entergy Arkansas, Inc.

In May 2012, FERC issued an order upholding its January 2010 ruling that Entergy should not have included additional charges to Ameren Missouri under a 165-megawatt power purchase agreement. Ameren Missouri paid Entergy the additional charges from 2007 through the expiration of the power purchase agreement on August 31, 2009. Pursuant to the order, in June 2012, Entergy paid Ameren Missouri $31 million, with $26 million recorded as a reduction to “Purchased power” expense and $5 million for interest recorded as “Miscellaneous income” in the statement of income. Ameren Missouri expects to refund to customers approximately $2 million of the funds received from Entergy as such funds relate to the period when the FAC was effective and, therefore, such costs were previously included in customer rates. Consequently, in June 2012, Ameren Missouri recorded a $2 million reduction, representing Ameren Missouri’s best estimate of its refund to customers, to its FAC under-recovered regulatory asset with a corresponding increase to expense. As noted above, Ameren Missouri, in its pending electric rate case, agreed to a settlement that will allow it to retain the refund received in June 2012 from Entergy relating to a power purchase agreement that existed prior to the implementation of the FAC. In July 2012, Entergy filed an appeal of FERC’s order to the United States Court of Appeals for the District of Columbia. A decision from the court is expected in 2013.

Ameren Illinois Electric Transmission Rate Refund

On July 19, 2012, FERC issued an order approving Ameren Illinois’ accounting for the Ameren Illinois Merger. As part of this order, FERC concluded that Ameren Illinois improperly included acquisition premiums, particularly goodwill, in determining its common equity used in its electric

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transmission formula rate, thereby inappropriately recovering a higher return on rate base from its electric transmission services customers. The order required Ameren Illinois to make refunds to customers for such improperly included amounts. In August 2012, Ameren Illinois filed a request for rehearing of this order. It is unknown when FERC will rule on Ameren’s rehearing request as it is under no deadline to do so. Based on Ameren Illinois’ examination of the FERC order and its calculation of the impact on electric transmission formula rates, Ameren Illinois concluded that no refund was warranted. If Ameren Illinois were to determine that a refund to its electric transmission customers is probable, a charge to earnings would be recorded for the refund in the period in which that determination was made.

2011 Wholesale Distribution Rate Case

In January 2011, Ameren Illinois filed a request with FERC to increase its annual revenues for electric delivery service for its wholesale customers by $11 million. These wholesale distribution revenues are treated as a deduction from Ameren Illinois’ revenue requirement in retail rate filings with the ICC. In March 2011, FERC issued an order authorizing the proposed rates to take effect, subject to refund when the final rates are determined. Ameren Illinois has reached an agreement with four of its nine wholesale customers. The impasse with the remaining five wholesale customers has resulted in FERC litigation. An initial decision by the FERC administrative law judge is expected in 2012, and a final FERC decision may be received during 2013. We cannot predict the ultimate outcome of this proceeding, but Ameren Illinois does not expect a material impact to its results of operations, financial position, or liquidity.

Combined Construction and Operating License

In 2008, Ameren Missouri filed an application with the NRC for a COL 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 COL application.

In March 2012, the DOE announced the availability of $452 million of investment funds for the design, engineering, manufacturing, and sale of American-made small modular reactors. In April 2012, Ameren Missouri entered into an agreement with Westinghouse to exclusively support Westinghouse’s application for the DOE’s small modular reactor investment funds. The DOE investment funding is intended to support engineering and design certifications and a COL for up to two small modular reactor designs over five years. Westinghouse submitted its application to the DOE in May 2012. The DOE is expected to issue a decision on awarding the investment funds in 2012.

If Westinghouse is awarded DOE’s small modular reactor investment funds, Ameren Missouri will seek a COL from the NRC for a Westinghouse small modular reactor or multiple reactors at its Callaway energy center site. A COL is issued by the NRC to permit construction and operation of a nuclear power plant at a specific site in accordance with established laws and regulations. Obtaining a COL from the NRC does not obligate Ameren Missouri to build a small modular reactor at the Callaway site; however, it does preserve the option to move forward in a timely fashion should conditions be right to build a small modular reactor in the future. A COL is valid for at least 40 years.

Ameren Missouri estimates the total cost to obtain the small modular reactor COL will be in the range of $80 million to $100 million. Ameren Missouri expects its incremental investment to obtain the small modular reactor COL to be minimal due to several factors, including the company’s capitalized investments in new nuclear energy center development of $69 million as of September 30, 2012, the DOE investment funds that would help support the COL application, and its agreement with Westinghouse. If the DOE does not approve Westinghouse’s application for the small modular reactor investment funds, Ameren Missouri is not obligated to pursue a COL for the Westinghouse small modular reactor design and may terminate its agreement with Westinghouse.

All of Ameren Missouri’s costs incurred to license additional nuclear generation at the Callaway site will remain capitalized while management pursues 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 - SHORT-TERM DEBT 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.

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The following table summarizes the borrowing activity and relevant interest rates under the 2010 Missouri Credit Agreement as of September 30, 2012, and excludes issued letters of credit:

2010 Missouri Credit Agreement ($800 million)	Ameren (Parent)		Ameren Missouri			Total
Average daily borrowings outstanding during 2012	$	-	$	1		$	1
Outstanding credit facility borrowings at period end		-		-			-
Weighted-average interest rate during 2012		-		4.15	%		4.15	%
Peak credit facility borrowings during 2012	$	-	$	50		$	50
Peak interest rate during 2012		-		4.15	%		4.15	%

The 2010 Illinois Credit Agreement and the 2010 Genco Credit Agreement were not utilized for borrowings during the nine months ended September 30, 2012. As of September 30, 2012, based on letters of credit issued under the 2010 Credit Agreements, as well as commercial paper outstanding as of such date, the aggregate amount of credit capacity available to Ameren (parent), Ameren Missouri, Ameren Illinois and Genco collectively at September 30, 2012, was $2.08 billion.

Commercial Paper

At September 30, 2012, Ameren had $5 million of commercial paper outstanding, which was included in “Short-term debt” on Ameren’s consolidated balance sheet. The average daily commercial paper balances outstanding during the nine months ended September 30, 2012, and 2011, were $58 million and $335 million, respectively. The weighted-average interest rates during the nine months ended September 30, 2012, and 2011, were 0.93% and 0.85%, respectively. The peak short-term commercial paper balances outstanding during the nine months ended September 30, 2012, and 2011, were $229 million and $435 million, respectively. The peak interest rates during the nine months ended September 30, 2012, and 2011, were 1.25% and 1.46%, respectively. Ameren Missouri and Ameren Illinois did not utilize their commercial paper programs during the nine months ended September 30, 2012.

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Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants within the 2010 Credit Agreements. See Note 4 – Credit Facility Borrowings and Liquidity in the Form 10-K for a detailed description of these 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 obtaining required regulatory authorizations. In addition, solely as it relates to borrowings under the 2010 Illinois Credit Agreement, it is a condition for any such borrowing that, at the time of and after giving effect to such borrowing, the borrower 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 its 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, 2012, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 47%, 47%, 42% and 44% 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, 2012, was 4.9 to 1. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2010 Credit Agreement.

None of the Ameren Companies’ credit facilities or financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. Management believes that the Ameren Companies were in compliance with the provisions and covenants of their credit facilities at September 30, 2012.

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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

Ameren Missouri, Ameren Illinois and Ameren Services may participate in the utility money pool as both lenders and borrowers. Ameren and AERG may participate in the utility money pool only as lenders. 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 made by participants, but is increased to the extent that the pool participants advance surplus funds to the utility money pool or remit 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. The average interest rate for borrowing under the utility money pool for the three and nine months ended September 30, 2012, was 0.14% and 0.13%, respectively. There were no utility money pool borrowings during the three and nine months ended September 30, 2011.

Non-state-regulated Subsidiaries

Ameren, Ameren Services, AER, Genco, AERG, Marketing Company, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company 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. All participants may borrow from or lend to the non-state-regulated money pool, except for Ameren Services, which may participate only as a borrower. The total amount available to the pool participants from the non-state-regulated subsidiary money pool at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. 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, 2012, was 0.52% and 0.64%, respectively (2011 - 0.83% and 0.89%, 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, 2012, and 2011.

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren Missouri

On September 11, 2012, Ameren Missouri issued $485 million principal amount of 3.90% senior secured notes due September 15, 2042, with interest payable semiannually on March 15 and September 15 of each year, beginning March 15, 2013. These notes are secured by first mortgage bonds. Ameren Missouri received net proceeds of $478 million. The proceeds

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were used, together with other available cash, to provide the funds necessary to complete Ameren Missouri’s tender offer on September 20, 2012, including the payment of interest and all related fees and expenses, and to retire the $173 million principal amount 5.25% senior secured notes that matured in September 2012.

On September 20, 2012, Ameren Missouri completed its tender offer to purchase for cash its outstanding 6.00% senior secured notes due 2018, 6.70% senior secured notes due 2019, 5.10% senior secured notes due 2018, and 5.10% senior secured notes due 2019. Any notes that were not tendered and purchased in the tender offer will remain outstanding and continue to be obligations of Ameren Missouri. The following table sets forth the aggregate principal amount of each series of notes repurchased, along with certain other items of the tender offer:

Senior Secured Notes	Principal Amount Repurchased		Premium Plus Accrued and Unpaid Interest(a)			Principal Amount Outstanding After Tender Offer
6.00% senior secured notes due 2018	$	71	$	19		$	179
6.70% senior secured notes due 2019		121		35			329
5.10% senior secured notes due 2018		1		(b	)		199
5.10% senior secured notes due 2019		56		12			244

(a) The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $485 million 3.90% senior secured notes.

(b) Amount is less than $1 million.

Ameren Illinois

On August 20, 2012, Ameren Illinois issued $400 million principal amount of 2.70% senior secured notes due September 1, 2022, with interest payable semiannually on March 1 and September 1 of each year, beginning March 1, 2013. These notes are secured by first mortgage bonds. Ameren Illinois received net proceeds of $397 million. The proceeds were used, together with other available cash, to provide the funds necessary to complete Ameren Illinois’ tender offer on August 27, 2012, including the payment of interest and all related fees and expenses, and to redeem all $51 million principal amount of 5.50% pollution control revenue bonds at par value plus accrued interest.

On August 27, 2012, Ameren Illinois completed its tender offer to purchase for cash its outstanding 9.75% senior secured notes due 2018 and 6.25% senior secured notes due 2018. Any notes that were not tendered and purchased in the tender offer will remain outstanding and continue to be obligations of Ameren Illinois. The following table sets forth the aggregate principal amount of each series of notes repurchased, along with certain other items of the tender offer:

Senior Secured Notes	Principal Amount Repurchased		Premium Plus Accrued and Unpaid Interest(a)		Principal Amount Outstanding After Tender Offer
9.75% senior secured notes due 2018	$	87	$	36	$	313
6.25% senior secured notes due 2018		194		47		144

(a) The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $400 million 2.70% senior secured notes.

Indenture Provisions and Other Covenants

Ameren Missouri’s and Ameren Illinois’ indentures 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, a failure to achieve these ratios would not result in a default under these covenants and provisions, but would restrict the companies’ ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios and bonds and preferred stock issuable for the 12 months ended September 30, 2012, 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		>2.0		4.3	$	3,651			>2.5		113.8	$	2,175
Ameren Illinois		>2.0		7.3		3,374	(d)		>1.5		3.0		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 $485 million and $645 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 in 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.

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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, Genco and 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 after the Ameren Illinois Merger and AERG distribution. As of September 30, 2012, Ameren Illinois’ ratio of common stock equity to total capitalization was 57%.

Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these ratios for the 12 months ended and as of September 30, 2012:

	Required Ratio			Actual Ratio
Restricted payment interest coverage ratio(a)		>1.75	(a)		2.9
Additional indebtedness interest coverage ratio(b)		>2.50	(b)		2.9
Additional indebtedness debt-to-capital ratio(b)		<60%	(b)		43	%

(a) As of the date of the restricted payment, as defined, 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. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.

(b) Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Credit facility borrowings, including borrowings under the 2010 Genco Credit Agreement, and other borrowings from third-party, external sources are included in the definition of indebtedness and are 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 reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness.

Under the provisions of Genco’s indenture, Genco may not borrow additional funds from external, third-party sources if its interest coverage ratio is less than a specified minimum or its leverage ratio is greater than a specified maximum. Based on projections as of September 30, 2012, of its operating results and cash flows, Genco expects that, by the end of the first quarter of 2013, its interest coverage ratio will be less than the minimum ratio required for the company to borrow additional funds from external, third-party sources. Genco’s indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren’s control and, if a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time.

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

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Off-Balance-Sheet Arrangements

At September 30, 2012, 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 Ameren’s, Ameren Missouri’s, Ameren Illinois’ and Genco’s statement of income and statements of income (loss) and comprehensive income (loss) for the three and nine months ended September 30, 2012, and 2011:

	Three Months				Nine Months
	2012		2011		2012			2011
Ameren:(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	9	$	10	$	26		$	25
Interest income on industrial development revenue bonds		7		7		21			21
Interest and dividend income		-		1		5	(b)		3
Other		1		-		2			2
Total miscellaneous income	$	17	$	18	$	54		$	51
Miscellaneous expense:
Donations	$	3	$	1	$	18	(c)	$	4
Other		4		4		11			11
Total miscellaneous expense	$	7	$	5	$	29		$	15
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	8	$	8	$	23		$	22
Interest income on industrial development revenue bonds		7		7		21			21
Interest and dividend income		-		-		4	(b)		1
Other		-		1		-			1
Total miscellaneous income	$	15	$	16	$	48		$	45
Miscellaneous expense:
Donations	$	2	$	1	$	7		$	3
Other		2		1		4			5
Total miscellaneous expense	$	4	$	2	$	11		$	8
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	1	$	2	$	3		$	3
Interest and dividend income		-		-		-			1
Other		1		-		2			1
Total miscellaneous income	$	2	$	2	$	5		$	5
Miscellaneous expense:
Donations	$	1	$	1	$	11	(c)	$	1
Other		1		1		4			3
Total miscellaneous expense	$	2	$	2	$	15		$	4
Genco:
Miscellaneous income:
Other	$	1	$	1	$	1		$	1
Total miscellaneous income	$	1	$	1	$	1		$	1
Miscellaneous expense:
Other	$	1	$	-	$	1		$	-
Total miscellaneous expense	$	1	$	-	$	1		$	-

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

(b) Includes interest income relating to a refund of charges included in an expired power purchase agreement with Entergy. See Note 2 - Rate and Regulatory Matters for additional information.

(c) Includes Ameren Illinois’ one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and $1 million annual donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois’ participation in the formula ratemaking process.

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NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, electricity, 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 commodity contract volumes by commodity type as of September 30, 2012, and December 31, 2011:

	Quantity (in millions, except as indicated)
Commodity	Accrual & NPNS Contracts(a)						Cash Flow Hedges(b)						Other Derivatives(c)						Derivatives That Qualify for Regulatory Deferral(d)
	2012			2011			2012			2011			2012			2011			2012			2011
Coal (in tons)
Ameren Missouri		100			116			(e	)		(e	)		-			(e	)		(e	)		(e	)
Genco		28			24			(e	)		(e	)		5			(e	)		(e	)		(e	)
Other(f)		8			7			(e	)		(e	)		2			(e	)		(e	)		(e	)
Ameren		136			147			(e	)		(e	)		7			(e	)		(e	)		(e	)
Fuel oils (in gallons)(g)
Ameren Missouri		(e	)		(e	)		(e	)		(e	)		(e	)		(e	)		57			53
Genco		(e	)		(e	)		(e	)		(e	)		38			27			(e	)		(e	)
Other(f)		(e	)		(e	)		(e	)		(e	)		11			9			(e	)		(e	)
Ameren		(e	)		(e	)		(e	)		(e	)		49			36			57			53
Natural gas (in mmbtu)
Ameren Missouri		5			8			(e	)		(e	)		2			9			23			19
Ameren Illinois		11			42			(e	)		(e	)		(e	)		(e	)		137			174
Genco		(e	)		(e	)		(e	)		(e	)		40			7			(e	)		(e	)
Other(f)		(e	)		(e	)		(e	)		(e	)		-			1			(e	)		(e	)
Ameren		16			50			(e	)		(e	)		42			17			160			193
Power (in megawatthours)
Ameren Missouri		4			1			(e	)		(e	)		2			1			11			6
Ameren Illinois		21			11			(e	)		(e	)		(e	)		(e	)		16			24
Genco		(e	)		(e	)		(e	)		(e	)		-			-			(e	)		(e	)
Other(f)		64			61			14			17			58			30			(2	)		(9	)
Ameren		89			73			14			17			60			31			25			21
Renewable energy credits(h)
Ameren Missouri		3			4			(e	)		(e	)		(e	)		(e	)		(e	)		(e	)
Ameren Illinois		12			12			(e	)		(e	)		(e	)		(e	)		(e	)		(e	)
Other(f)		1			1			(e	)		(e	)		(e	)		(e	)		(e	)		(e	)
Ameren		16			17			(e	)		(e	)		(e	)		(e	)		(e	)		(e	)
Uranium (pounds in thousands)
Ameren Missouri & Ameren		5,262			5,553			(e	)		(e	)		(e	)		(e	)		215			148

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(a) Accrual contracts include commodity contracts that do not qualify as derivatives. Contracts through December 2017, March 2015, September 2035, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively, as of September 30, 2012.

(b) Contracts through December 2016 for power as of September 30, 2012.

(c) Contracts through December 2015, October 2016, April 2015, and December 2016 for coal, fuel oils, natural gas, and power, respectively, as of September 30, 2012.

(d) Contracts through October 2015, March 2017, May 2032, and September 2014 for fuel oils, natural gas, power, and uranium, respectively, as of September 30, 2012.

(e) Not applicable.

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

(g) Fuel oils consist of heating and crude oil.

(h) A renewable energy credit is created for every one megawatthour of renewable energy generated. Ameren contracts include renewable energy credits from solar, wind, and landfill gas-generated 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 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 or the statement of income and comprehensive 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 or the statement of income and comprehensive income.

Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value recorded as 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, or we do not choose to elect, 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 or the statement of income and comprehensive income in the period in which the change occurs.

Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. The Ameren Companies did not elect to adopt this guidance for any eligible commodity contracts or other items.

The following table presents the carrying value and balance sheet location of all derivative instruments as of September 30, 2012, and December 31, 2011:

	Balance Sheet Location	Ameren(a)		Ameren Missouri			Ameren Illinois			Genco
2012:
Derivative assets designated as hedging instruments
Commodity contracts:
Power	MTM derivative assets	$	23	$	(b	)	$	(b	)	$	(b	)
	Other assets		23		-			-			-
	Total assets	$	46	$	-		$	-		$	-
Derivative liabilities designated as hedging instruments
Commodity contracts:
Power	MTM derivative liabilities	$	2	$	(b	)	$	-		$	(b	)
	Total liabilities	$	2	$	-		$	-		$	-

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	Balance Sheet Location	Ameren(a)			Ameren Missouri			Ameren Illinois			Genco
Derivative assets not designated as hedging instruments(c)
Commodity contracts:
Fuel oils	MTM derivative assets	$	17		$	(b	)	$	(b	)	$	(b	)
	Other current assets		-			11			-			6
	Other assets		6			4			-			1
Natural gas	MTM derivative assets		9			(b	)		(b	)		(b	)
	Other current assets		-			1			2			6
	Other assets		2			1			-			1
Power	MTM derivative assets		85			(b	)		(b	)		(b	)
	Other current assets		-			25			-			-
	Other assets		32			3			-			-
	Total assets	$	151		$	45		$	2		$	14
Derivative liabilities not designated as hedging instruments(c)
Commodity contracts:
Coal	MTM derivative liabilities	$	6		$	(b	)	$	-		$	(b	)
	Other current liabilities		-			-			-			5
	Other deferred credits and liabilities		4			-			-			3
Fuel oils	MTM derivative liabilities		1			(b	)		-			(b	)
	Other current liabilities		-			1			-			-
	Other deferred credits and liabilities		3			1			-			2
Natural gas	MTM derivative liabilities		71			(b	)		59			(b	)
	Other current liabilities		-			8			-			4
	Other deferred credits and liabilities		54			9			45			-
Power	MTM derivative liabilities		74			(b	)		19			(b	)
	MTM derivative liabilities - affiliates		(b	)		(b	)		59			(b	)
	Other current liabilities		-			9			-			-
	Other deferred credits and liabilities		111			2			87			-
Uranium .	MTM derivative liabilities		1			(b	)		-			(b	)
	Other current liabilities		-			1			-			-
	Other deferred credits and liabilities		1			1			-			-
	Total liabilities	$	326		$	32		$	269		$	14
2011:
Derivative assets designated as hedging instruments
Commodity contracts:
Power	MTM derivative assets	$	8		$	(b	)	$	(b	)	$	(b	)
	Other assets		16			-			-			-
	Total assets	$	24		$	-		$	-		$	-
Derivative liabilities designated as hedging instruments
Commodity contracts:
Power	Other deferred credits and liabilities	$	1		$	-		$	-		$	-
	Total liabilities	$	1		$	-		$	-		$	-
Derivative assets not designated as hedging instruments(c)
Commodity contracts:
Fuel oils	MTM derivative assets	$	29		$	(b	)	$	(b	)	$	(b	)
	Other current assets		-			17			-			10
	Other assets		8			6			-			1
Natural gas	MTM derivative assets		6			(b	)		(b	)		(b	)
	Other current assets		-			2			1			2
	Other assets		-			-			1			-
Power	MTM derivative assets		72			(b	)		(b	)		(b	)
	Other current assets		-			30			-			-
	Other assets		99			-			77			-
	Total assets	$	214		$	55		$	79		$	13
Derivative liabilities not designated as hedging instruments(c)
Commodity contracts:
Fuel oils	MTM derivative liabilities	$	2		$	(b	)	$	-		$	(b	)
	Other current liabilities		-			1			-			1
Natural gas	MTM derivative liabilities		106			(b	)		90			(b	)
	Other current liabilities		-			13			-			2
	Other deferred credits and liabilities		92			13			79			-
Power	MTM derivative liabilities		53			(b	)		9			(b	)
	MTM derivative liabilities - affiliates		(b	)		(b	)		200			(b	)
	Other current liabilities		-			9			-			-
	Other deferred credits and liabilities		26			-			8			-
Uranium	Other deferred credits and liabilities		1			1			-			-
	Total liabilities	$	280		$	37		$	386		$	3

(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.

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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, 2012, and December 31, 2011:

	Ameren			Ameren Missouri			Ameren Illinois			Genco			Other(a)
2012:
Cumulative gains (losses) deferred in accumulated OCI:
Power derivative contracts(b)	$	44		$	-		$	-		$	-		$	44
Interest rate derivative contracts(c)(d)		(8	)		-			-			(8	)		-
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Fuel oils derivative contracts(e)		10			10			-			-			-
Natural gas derivative contracts(f)		(117	)		(15	)		(102	)		-			-
Power derivative contracts(g)		(88	)		18			(165	)		-			59
Uranium derivative contracts(h)		(2	)		(2	)		-			-			-
2011:
Cumulative gains (losses) deferred in accumulated OCI:
Power derivative contracts(b)	$	19		$	-		$	-		$	-		$	19
Interest rate derivative contracts(c)(d)		(8	)		-			-			(8	)		-
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Fuel oils derivative contracts(e)		19			19			-			-			-
Natural gas derivative contracts(f)		(191	)		(24	)		(167	)		-			-
Power derivative contracts(g)		81			21			(140	)		-			200
Uranium derivative contracts(h)		(1	)		(1	)		-			-			-

(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 2016 as of September 30, 2012. Based on market prices at September 30, 2012, net pre-tax unrealized gains of $21 million is expected to be reclassified into earnings during the next 12 months as the hedged transactions occur. However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices.

(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 covered the first 10 years of debt that has a 30-year maturity, and the gain in OCI was amortized over a 10-year period that began in June 2002. The balance of the gain was fully amortized as of June 30, 2012. The carrying value at December 31, 2011, was less than $1 million.

(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, 2012, and December 31, 2011, was a loss of $8 million and $9 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.

(e) Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through October 2015 as of September 30, 2012. Current gains deferred as regulatory liabilities include $9 million and $9 million at Ameren and Ameren Missouri as of September 30, 2012, respectively. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of September 30, 2012, respectively.

(f) Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through March 2017 at Ameren and Ameren Missouri and through October 2016 at Ameren Illinois, in each case as of September 30, 2012. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Illinois, respectively, as of September 30, 2012. Current losses deferred as regulatory assets include $67 million, $8 million, and $59 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of September 30, 2012.

(g) Represents net losses 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 2015 at Ameren Missouri, in each case as of September 30, 2012. Current gains deferred as regulatory liabilities include $24 million and $24 million at Ameren and Ameren Missouri, respectively, as of September 30, 2012. Current losses deferred as regulatory assets include $26 million, $8 million, and $78 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of September 30, 2012.

(h) Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through September 2014 as of September 30, 2012. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of September 30, 2012, respectively.

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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) the 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, 2012, and December 31, 2011, 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 accrual and 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
2012:
AMO	$	-	$	-	$	3	$	4	$	20	$	4		$	1	$	-	$	32
AIC		-		-		1		-		1		-			-		-		2
Genco		-		6		2		-		5		-			3		-		16
Other(b)		128		4		39		10		18		362	(c)		1		90		652
Ameren	$	128	$	10	$	45	$	14	$	44	$	366		$	5	$	90	$	702
2011:
AMO	$	1	$	35	$	1	$	4	$	26	$	4		$	-	$	-	$	71
AIC		-		-		84		-		1		-			-		-		85
Genco		-		1		1		2		6		-			3		-		13
Other(b)		275		1		3		10		51		194	(c)		-		87		621
Ameren	$	276	$	37	$	89	$	16	$	84	$	198		$	3	$	87	$	790

(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 for purposes of this disclosure, 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.

(c) Primarily composed of Marketing Company’s exposure to NPNS contracts with terms through September 2035.

The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held. The amount of cash collateral held by Ameren and Marketing Company from counterparties is based on the contractual rights under the agreements to seek collateral, as well as the maximum exposure as calculated under the individual master trading and netting agreements, was $2 million from marketing companies at September 30, 2012. Cash collateral held by Ameren and Marketing Company was less than $1 million from retail companies at December 31, 2011. As of September 30, 2012, other collateral used to reduce exposure consisted of letters of credit in the amount of $7 million held by Ameren and Marketing Company. As of December 31, 2011, other collateral used to reduce exposure consisted of letters of credit in the amount of $9 million, $1 million, $1 million, and $7 million held by Ameren, Ameren Missouri, Genco, and Marketing Company, respectively.

36

The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of September 30, 2012, and December 31, 2011:

	Affiliates(a)		Coal Producers		Commodity Marketing Companies		Electric Utilities		Financial Companies		Municipalities/ Cooperatives			Oil and Gas Companies		Retail Companies		Total
2012:
AMO	$	-	$	-	$	2	$	3	$	14	$	4		$	-	$	-	$	23
AIC		-		-		1		-		-		-			-		-		1
Genco		-		4		-		-		4		-			1		-		9
Other(b)		126		3		32		3		16		355	(c)		1		89		625
Ameren	$	126	$	7	$	35	$	6	$	34	$	359		$	2	$	89	$	658
2011:
AMO	$	1	$	35	$	1	$	3	$	22	$	4		$	-	$	-	$	66
AIC		-		-		84		-		-		-			-		-		84
Genco		-		-		-		1		1		-			2		-		4
Other(b)		273		-		3		5		42		187	(c)		-		86		596
Ameren	$	274	$	35	$	88	$	9	$	65	$	191		$	2	$	86	$	750

(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 for purposes of this disclosure, 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.

(c) Primarily composed of Marketing Company’s exposure to NPNS contracts with terms through September 2035.

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, 2012, and December 31, 2011, 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, 2012, or December 31, 2011, 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)
2012:
Ameren Missouri	$	93	$	4	$	80
Ameren Illinois		156		75		72
Genco		53		-		38
Other(c)		91		8		54
Ameren	$	393	$	87	$	244
2011:
Ameren Missouri	$	102	$	8	$	86
Ameren Illinois		220		96		125
Genco		55		1		58
Other(c)		79		11		63
Ameren	$	456	$	116	$	332

(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).

37

Cash Flow Hedges

The following table presents the pretax net gain or loss for the three and nine months ended September 30, 2012, and 2011, associated with derivative instruments designated as cash flow hedges.

	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
2012:
Ameren:(d)
Power	$	(2	)	Operating Revenues - Electric	$	(1	)	Operating Revenues - Electric	$	(4	)
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
Genco:
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
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		-
Nine Months
2012:
Ameren:(d)
Power	$	21		Operating Revenues - Electric	$	5		Operating Revenues - Electric	$	(3	)
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
Genco:
Interest rate(e)		-		Interest Charges		(f	)	Interest Charges		-
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		-

(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, 2012 and 2011:

		Location of Gain (Loss) Recognized in Income	Gain (Loss) Recognized in Income
			Three Months						Nine Months
			2012			2011			2012			2011
Ameren(a)	Coal	Operating Expenses - Fuel	$	-		$	-		$	(10	)	$	-
	Fuel oils	Operating Expenses - Fuel		6			(14	)		(7	)		(4	)
	Natural gas (generation)	Operating Expenses - Fuel		(1	)		-			4			-
	Power	Operating Revenues - Electric		4			2			10			(5	)
		Total	$	9		$	(12	)	$	(3	)	$	(9	)
Ameren Missouri	Natural gas (generation)	Operating Expenses - Fuel	$	-		$	-		$	-		$	(1	)
Genco	Coal	Operating Expenses - Fuel	$	-		$	-		$	(8	)	$	-
	Fuel oils	Operating Expenses - Fuel		5			(10	)		(5	)		(3	)
	Natural gas (generation)	Operating Expenses - Fuel		(1	)		1			3			1
	Power	Operating Revenues		-			(2	)		-			(3	)
		Total	$	4		$	(11	)	$	(10	)	$	(5	)

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

38

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, 2012, and 2011:

		Gain (Loss) Recognized in Regulatory  Liabilities or Regulatory Assets
		Three Months						Nine Months
		2012			2011			2012			2011
Ameren(a)	Fuel oils	$	5		$	(20	)	$	(9	)	$	(4	)
	Natural gas		46			(11	)		74			23
	Power		(6	)		13			(169	)		103
	Uranium		(1	)		1			(1	)		(3	)
	Total	$	44		$	(17	)	$	(105	)	$	119
Ameren Missouri	Fuel oils	$	5		$	(20	)	$	(9	)	$	(4	)
	Natural gas		6			-			9			4
	Power		(6	)		(7	)		(3	)		16
	Uranium		(1	)		1			(1	)		(3	)
	Total	$	4		$	(26	)	$	(4	)	$	13
Ameren Illinois	Natural gas	$	40		$	(11	)	$	65		$	19
	Power		56			70			(25	)		218
	Total	$	96		$	59		$	40		$	237

(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. The fair value of the financial contracts included in “MTM derivative liabilities - affiliates” on Ameren Illinois’ balance sheet totaled $59 million and $200 million at September 30, 2012, and December 31, 2011, respectively. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.

NOTE 7 - FAIR VALUE MEASUREMENTS

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives and assets, including cash and cash equivalents and listed equity securities, such as those held in Ameren Missouri’s Nuclear Decommissioning Trust Fund.

The market approach is used to measure the fair value of equity securities held in Ameren Missouri’s Nuclear Decommissioning Trust Fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants and the trustee and investment managers. The S&P 500 index is comprised of stocks of large capitalization companies.

Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri’s Nuclear Decommissioning Trust Fund, including corporate bonds and other fixed-income securities, U.S. treasury and agency securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.

Fixed income securities are valued using prices from independent, industry recognized data vendors who provide values that are either exchange based or matrix based. The fair value measurements of fixed income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices. Level 2 fixed income securities in the Nuclear Decommissioning Trust Fund are comprised primarily of corporate bonds, asset-backed securities and U.S. agency bonds.

Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets.

39

Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint. Natural gas derivative contracts are valued based upon exchange closing prices without significant unobservable adjustments. Power derivative contracts are valued based upon the use of multiple forward prices provided by third parties. The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments.

Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable, including the financial contracts entered into between Ameren Illinois and Marketing Company as part of the 2007 Illinois Electric Supply Agreement. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our fair value estimation process, an evaluation of all sources is performed to identify any anomalies or potential errors.

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.

The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the period ended September 30, 2012:

		Fair Value					Valuation Technique(s)	Unobservable Input	Range [Weighted Average]
		Assets Liabilities
Level 3 Derivative asset and liability - commodity contracts(a):
Ameren(b)	Fuel oils	$	8	$	(2	)	Discounted cash flow	Escalation rate(%)(c)	.25 - .70 [.56]
								Counterparty credit risk(%)(d),(e)	.12 - 9 [2]
							Option model	Volatilities(%)(c)	22 - 30 [27]
	Power(f)		146		(174	)	Option model	Volatilities(%)(d)	14 - 61 [18]
								Average bid/ask consensus peak and offpeak pricing - forwards/swaps ($/MWh)(d)	22 - 47 [33]
							Discounted cash flow	Average bid/ask consensus peak and offpeak pricing - forwards/swaps ($/MWh)(d)	16 - 55 [32]
								Estimated auction price for FTRs ($/MW)(c)	(19,671) -133,769 [166]
								Nodal basis ($/MWh)(d)	(12) - 2 [(1)]
								Counterparty credit risk(%)(d),(e)	.06 - 12 [3]
								Ameren credit risk(%)(d),(e)	2 - 4 [4]
							Fundamental energy production model	Estimated future gas prices ($/mmbtu)(c)	4 - 7 [6]
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(c)	5 - 7 [6]
	Uranium		-		(2	)	Discounted cash flow	Average bid/ask consensus pricing ($/pound)(c)	45 - 55 [47]
Ameren Missouri	Fuel oils	$	7	$	(2	)	Discounted cash flow	Escalation rate(%)(c)	.25 - .70 [.59]
								Counterparty credit risk(%)(d),(e)	.12 - 4 [2]

40

		Fair Value					Valuation Technique(s)	Unobservable Input	Range [Weighted Average]
		Assets Liabilities
							Option model	Volatilities(%)(c)	22 - 30 [27]
	Power(f)		20		(5	)	Option model	Volatilities(%)(d)	49 - 61 [56]
								Average bid/ask consensus peak and offpeak pricing - ($/MWh)(d)	21 - 26 [22]
							Discounted cash flow	Average bid/ask consensus peak and offpeak pricing - forwards/swaps ($/MWh)(d)	19 - 58 [35]
								Estimated auction price for FTRs ($/MW)(c)	23 - 2,120 [139]
								Nodal basis ($/MWh)(d)	(7) - (.40) [(4)]
								Counterparty credit risk(%)(d),(e)	.22 - 9 [3]
								Ameren Missouri credit risk(%)(d),(e)	2
	Uranium		-		(2	)	Discounted cash flow	Average bid/ask consensus pricing ($/pound)(c)	45 - 55 [47]
Ameren Illinois	Power(f)	$	-	$	(165	)	Discounted cash flow	Average bid/ask consensus peak and offpeak pricing - forwards/swaps ($/MWh)(c)	17 - 47 [27]
								Nodal basis ($/MWh)(c)	(5) - (.91) [(3)]
								Ameren Illinois credit risk (%)(d),(e)	4
							Fundamental energy production model	Estimated future gas prices ($/mmbtu)(c)	4 - 7 [5]
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(c)	5 - 7 [6]
Genco	Fuel oils	$	1	$	-		Discounted cash flow	Escalation rate(c)	.25 - .70 [.64]
								Counterparty credit risk (%)(d),(e)	.12 - 9 [3]
							Option model	Volatilities (%)(c)	22 - 30 [24]

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

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

(c) Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.

(d) Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.

(e) Counterparty credit risk is only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri, Ameren Illinois, and Genco credit risk is only applied to counterparties with derivative liability balances.

(f) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak through 2016. Valuations beyond 2016 utilize fundamentally modeled pricing by month for peak and off-peak.

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 and $1 million in the first nine months of 2012 and 2011, respectively, related to valuation adjustments for counterparty default risk. Genco recorded losses of less than $1 million and less than $1 million in the first nine months of 2012 and 2011, respectively, related to valuation adjustments for counterparty default risk. At September 30, 2012, the counterparty default risk (asset)/liability valuation adjustment related to derivative contracts totaled $5 million, less than $(1) million, $9 million, and less than $(1) million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. At December 31, 2011, the counterparty default risk (asset)/liability valuation adjustment related to derivative contracts totaled $1 million, less than $1 million, $19 million, and less than $(1) million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

41

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, 2012:

		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):
	Fuel oils	$	15	$	-	$	8	$	23
	Natural gas		7		4		-		11
	Power		-		17		146		163
	Total derivative assets - commodity contracts	$	22	$	21	$	154	$	197
	Nuclear Decommissioning Trust Fund(c):
	Cash and cash equivalents	$	2	$	-	$	-	$	2
	Equity securities:
	U.S. large capitalization		270		-		-		270
	Debt securities:
	Corporate bonds		-		46		-		46
	Municipal bonds		-		1		-		1
	U.S. treasury and agency securities		-		78		-		78
	Asset-backed securities		-		11		-		11
	Other		-		1		-		1
	Total Nuclear Decommissioning Trust Fund	$	272	$	137	$	-	$	409
	Total Ameren	$	294	$	158	$	154	$	606
Ameren	Derivative assets - commodity contracts(b):
Missouri	Fuel oils	$	8	$	-	$	7	$	15
	Natural gas		1		1		-		2
	Power		-		8		20		28
	Total derivative assets - commodity contracts	$	9	$	9	$	27	$	45
	Nuclear Decommissioning Trust Fund(c):
	Cash and cash equivalents	$	2	$	-	$	-	$	2
	Equity securities:
	U.S. large capitalization		270		-		-		270
	Debt securities:
	Corporate bonds		-		46		-		46
	Municipal bonds		-		1		-		1
	U.S. treasury and agency securities		-		78		-		78
	Asset-backed securities		-		11		-		11
	Other		-		1		-		1
	Total Nuclear Decommissioning Trust Fund	$	272	$	137	$	-	$	409
	Total Ameren Missouri	$	281	$	146	$	27	$	454
Ameren	Derivative assets - commodity contracts(b):
Illinois	Natural gas	$	-	$	2	$	-	$	2
Genco	Derivative assets - commodity contracts(b):
	Fuel oils	$	6	$	-	$	1	$	7
	Natural gas		6		1		-		7
	Total Genco	$	12	$	1	$	1	$	14
Liabilities:
Ameren(a)	Derivative liabilities - commodity contracts(b):
	Coal	$	10	$	-	$	-	$	10
	Fuel oils		2		-		2		4
	Natural gas		12		113		-		125
	Power		-		13		174		187
	Uranium		-		-		2		2
	Total Ameren	$	24	$	126	$	178	$	328
Ameren	Derivative liabilities - commodity contracts(b):
Missouri	Fuel oils	$	-	$	-	$	2	$	2
	Natural gas		9		8		-		17
	Power		-		6		5		11
	Uranium		-		-		2		2
	Total Ameren Missouri	$	9	$	14	$	9	$	32
Ameren	Derivative liabilities - commodity contracts(b):
Illinois	Natural gas	$	-	$	104	$	-	$	104
	Power		-		-		165		165
	Total Ameren Illinois	$	-	$	104	$	165	$	269

42

		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
Genco	Derivative liabilities - commodity contracts(b):
	Coal	$	8	$	-	$	-	$	8
	Fuel oils		2		-		-		2
	Natural gas		3		1		-		4
	Total Genco	$	13	$	1	$	-	$	14

(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 $(2) 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, 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):
	Fuel oils	$	33	$	-	$	4	$	37
	Natural gas		4		-		2		6
	Power		-		2		193		195
	Total derivative assets - commodity contracts	$	37	$	2	$	199	$	238
	Nuclear Decommissioning Trust Fund(c):
	Cash and cash equivalents	$	3	$	-	$	-	$	3
	Equity securities:
	U.S. large capitalization		234		-		-		234
	Debt securities:
	Corporate bonds		-		44		-		44
	Municipal bonds		-		1		-		1
	U.S. treasury and agency securities		-		65		-		65
	Asset-backed securities		-		10		-		10
	Other		-		1		-		1
	Total Nuclear Decommissioning Trust Fund	$	237	$	121	$	-	$	358
	Total Ameren	$	274	$	123	$	199	$	596
Ameren	Derivative assets - commodity contracts(b):
Missouri	Fuel oils	$	20	$	-	$	3	$	23
	Natural gas		2		-		-		2
	Power		-		1		29		30
	Total derivative assets - commodity contracts	$	22	$	1	$	32	$	55
	Nuclear Decommissioning Trust Fund(c):
	Cash and cash equivalents	$	3	$	-	$	-	$	3
	Equity securities:
	U.S. large capitalization		234		-		-		234
	Debt securities:
	Corporate bonds		-		44		-		44
	Municipal bonds		-		1		-		1
	U.S. treasury and agency securities		-		65		-		65
	Asset-backed securities		-		10		-		10
	Other		-		1		-		1
	Total Nuclear Decommissioning Trust Fund	$	237	$	121	$	-	$	358
	Total Ameren Missouri	$	259	$	122	$	32	$	413
Ameren	Derivative assets - commodity contracts(b):
Illinois	Natural gas	$	-	$	-	$	2	$	2
	Power		-		-		77		77
	Total Ameren Illinois	$	-	$	-	$	79	$	79
Genco	Derivative assets - commodity contracts(b):
	Fuel oils	$	10	$	-	$	1	$	11
	Natural gas		2		-		-		2
	Total Genco	$	12	$	-	$	1	$	13

43

		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
Liabilities:
Ameren(a)	Derivative liabilities - commodity contracts(b):
	Fuel oils	$	2	$	-	$	-	$	2
	Natural gas		22		-		176		198
	Power		-		2		78		80
	Uranium		-		-		1		1
	Total Ameren	$	24	$	2	$	255	$	281
Ameren	Derivative liabilities - commodity contracts(b):
Missouri	Fuel oils	$	1	$	-	$	-	$	1
	Natural gas		12		-		14		26
	Power		-		1		8		9
	Uranium		-		-		1		1
	Total Ameren Missouri	$	13	$	1	$	23	$	37
Ameren	Derivative liabilities - commodity contracts(b):
Illinois	Natural gas		7		-		162		169
	Power		-		-		217		217
	Total Ameren Illinois	$	7	$	-	$	379	$	386
Genco	Derivative liabilities - commodity contracts(b):
	Fuel oils	$	1	$	-	$	-	$	1
	Natural gas		2		-		-		2
	Total Genco	$	3	$	-	$	-	$	3

(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 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, 2012:

	Net derivative commodity contracts
Three Months	Ameren Missouri			Ameren Illinois			Genco				Other(c)			Ameren
Fuel oils:
Beginning balance at July 1, 2012	$	3		$	(a	)	$	1			$	-		$	4
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		1			(a	)		(a	)			(a	)		1
Total realized and unrealized gains (losses)		1			(a	)		-				-			1
Purchases		2			(a	)		(1	)			-			1
Sales		(1	)		(a	)		-				-			(1	)
Transfers out of Level 3		-			(a	)		1				-			1
Ending balance at September 30, 2012	$	5		$	(a	)	$	1			$	-		$	6
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	2		$	(a	)	$	-			$	-		$	2
Power:
Beginning balance at July 1, 2012	$	26		$	(221	)	$	-			$	185		$	(10	)
Realized and unrealized gains (losses):
Included in earnings(b)		-			-			-				4			4
Included in OCI		-			-			-				(4	)		(4	)
Included in regulatory assets/liabilities		(4	)		2			(a	)	��		(4	)		(6	)
Total realized and unrealized gains (losses)		(4	)		2			-				(4	)		(6	)
Purchases		-			-			-				3			3
Sales		(1	)		-			-				(4	)		(5	)
Settlements		(4	)		54			-				(56	)		(6	)
Transfers out of Level 3		(2	)		-			-				(2	)		(4	)
Ending balance at September 30, 2012	$	15		$	(165	)	$	-			$	122		$	(28	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	(5	)	$	(2	)	$	-			$	(10	)	$	(17	)
Uranium:
Beginning balance at July 1, 2012	$	(1	)	$	(a	)	$	(a	)		$	(a	)	$	(1	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(1	)		(a	)		(a	)			(a	)		(1	)
Total realized and unrealized gains (losses)		(1	)		(a	)		(a	)			(a	)		(1	)
Ending balance at September 30, 2012	$	(2	)	$	(a	)	$	(a	)		$	(a	)	$	(2	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	(1	)	$	(a	)	$	(a	)		$	(a	)	$	(1	)

44

(a) Not applicable.

(b) Net gains and losses on fuel oils 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, including the elimination of financial power contracts between Ameren Illinois and Marketing Company.

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 Missouri			Ameren Illinois			Genco			Other(c)			Ameren
Fuel oils:
Beginning balance at July 1, 2011	$	41		$	(a	)	$	21		$	6		$	68
Realized and unrealized gains (losses):
Included in earnings(b)		-			(a	)		(5	)		(2	)		(7	)
Included in regulatory assets/liabilities		(12	)		(a	)		(a	)		(a	)		(12	)
Total realized and unrealized gains (losses)		(12	)		(a	)		(5	)		(2	)		(19	)
Purchases		2			(a	)		(1	)		-			1
Sales		(1	)		(a	)		-			-			(1	)
Settlements		(10	)		(a	)		(7	)		(2	)		(19	)
Ending balance at September 30, 2011	$	20		$	(a	)	$	8		$	2		$	30
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	(14	)	$	(a	)	$	(6	)	$	(2	)	$	(22	)
Natural gas:
Beginning balance at July 1, 2011	$	(11	)	$	(106	)	$	-		$	-		$	(117	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(2	)		(31	)		(a	)		(a	)		(33	)
Total realized and unrealized gains (losses)		(2	)		(31	)		-			-			(33	)
Purchases		-			(1	)		-			-			(1	)
Settlements		2			22			-			(1	)		23
Ending balance at September 30, 2011	$	(11	)	$	(116	)	$	-		$	(1	)	$	(128	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	(2	)	$	(27	)	$	-		$	-		$	(29	)
Power:
Beginning balance at July 1, 2011	$	25		$	(204	)	$	1		$	295		$	117
Realized and unrealized gains (losses):
Included in OCI		-			-			-			(7	)		(7	)
Included in regulatory assets/liabilities		-			35			(a	)		(10	)		25
Total realized and unrealized gains (losses)		-			35			-			(17	)		18
Purchases		-			-			-			2			2
Sales		-			-			-			(1	)		(1	)
Settlements		(7	)		35			(1	)		(45	)		(18	)
Transfers into Level 3		-			-			-			(2	)		(2	)
Transfers out of Level 3		-			-			-			(2	)		(2	)
Ending balance at September 30, 2011	$	18		$	(134	)	$	-		$	230		$	114
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	-		$	26		$	-		$	(4	)	$	22
Uranium:
Beginning balance at July 1, 2011	$	(2	)	$	(a	)	$	(a	)	$	(a	)	$	(2	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		-			(a	)		(a	)		(a	)		-
Total realized and unrealized gains (losses)		-			(a	)		(a	)		(a	)		-
Settlements		1			(a	)		(a	)		(a	)		1
Ending balance at September 30, 2011	$	(1	)	$	(a	)	$	(a	)	$	(a	)	$	(1	)
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 fuel oils 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, including the elimination of financial power contracts between Ameren Illinois and Marketing Company.

45

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, 2012:

	Net derivative commodity contracts
Nine Months	Ameren Missouri			Ameren Illinois			Genco			Other(c)			Ameren
Fuel oils:
Beginning balance at January 1, 2012	$	3		$	(a	)	$	1		$	-		$	4
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(1	)		(a	)		(a	)		(a	)		(1	)
Total realized and unrealized gains (losses)		(1	)		(a	)		-			-			(1	)
Purchases		4			(a	)		-			-			4
Sales		(2	)		(a	)		-			-			(2	)
Settlements		(1	)		(a	)		-			-			(1	)
Transfers into Level 3		2			(a	)		-			-			2
Ending balance at September 30, 2012	$	5		$	(a	)	$	1		$	-		$	6
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	(1	)	$	(a	)	$	-		$	-		$	(1	)
Natural gas:
Beginning balance at January 1, 2012	$	(14	)	$	(160	)	$	-		$	-		$	(174	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(2	)		(26	)		(a	)		(a	)		(28	)
Total realized and unrealized gains (losses)		(2	)		(26	)		-			-			(28	)
Settlements		1			16			-			-			17
Transfer out of Level 3		15			170			-			-			185
Ending balance at September 30, 2012	$	-		$	-		$	-		$	-		$	-
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	7		$	-		$	-		$	-		$	7
Power:
Beginning balance at January 1, 2012	$	21		$	(140	)	$	-		$	234		$	115
Realized and unrealized gains (losses):
Included in earnings(b)		-			-			-			11			11
Included in OCI		-			-			-			30			30
Included in regulatory assets/liabilities		5			(219	)		(a	)		40			(174	)
Total realized and unrealized gains (losses)		5			(219	)		-			81			(133	)
Purchases		22			-			-			8			30
Sales		(1	)		-			-			3			2
Settlements		(28	)		194			-			(206	)		(40	)
Transfers into Level 3		-			-			-			1			1
Transfers out of Level 3		(4	)		-			-			1			(3	)
Ending balance at September 30, 2012	$	15		$	(165	)	$	-		$	122		$	(28	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	(1	)	$	(187	)(d)	$	-		$	44		$	(144	)
Uranium:
Beginning balance at January 1, 2012	$	(1	)	$	(a	)	$	(a	)	$	(a	)	$	(1	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(1	)		(a	)		(a	)		(a	)		(1	)
Total realized and unrealized gains (losses)		(1	)		(a	)		(a	)		(a	)		(1	)
Ending balance at September 30, 2012	$	(2	)	$	(a	)	$	(a	)	$	(a	)	$	(2	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	(1	)	$	(a	)	$	(a	)	$	(a	)	$	(1	)

(a) Not applicable.

(b) Net gains and losses on fuel oils 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, including the elimination of financial power contracts between Ameren Illinois and Marketing Company.

(d) The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois’ swap contracts, which expire in May 2032.

46

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 Missouri			Ameren Illinois			Genco			Other(c)			Ameren
Fuel oils:
Beginning balance at January 1, 2011	$	30		$	(a	)	$	17		$	4		$	51
Realized and unrealized gains (losses):
Included in earnings(b)		-			(a	)		7			3			10
Included in regulatory assets/liabilities		10			(a	)		(a	)		(a	)		10
Total realized and unrealized gains (losses)		10			(a	)		7			3			20
Purchases		4			(a	)		(1	)		-			3
Sales		(1	)		(a	)		-			-			(1	)
Settlements		(23	)		(a	)		(15	)		(5	)		(43	)
Ending balance at September 30, 2011	$	20		$	(a	)	$	8		$	2		$	30
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	2		$	(a	)	$	1		$	1		$	4
Natural gas:
Beginning balance at January 1, 2011	$	(14	)	$	(134	)	$	-		$	-		$	(148	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(3	)		(43	)		(a	)		(a	)		(46	)
Total realized and unrealized gains (losses)		(3	)		(43	)		-			-			(46	)
Purchases		-			1			-			(1	)		-
Settlements		6			60			-			-			66
Ending balance at September 30, 2011	$	(11	)	$	(116	)	$	-		$	(1	)	$	(128	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	(3	)	$	(31	)	$	-		$	-		$	(34	)
Power:
Beginning balance at January 1, 2011	$	2		$	(352	)	$	3		$	383		$	36
Realized and unrealized gains (losses):
Included in earnings(b)		-			-			(1	)		(17	)		(18	)
Included in OCI		-			-			-			(2	)		(2	)
Included in regulatory assets/liabilities		6			82			(a	)		1			89
Total realized and unrealized gains (losses)		6			82			(1	)		(18	)		69
Purchases		29			-			-			32			61
Sales		-			-			-			(17	)		(17	)
Settlements		(19	)		136			(2	)		(149	)		(34	)
Transfers into Level 3		(1	)		-			-			-			(1	)
Transfers out of Level 3		1			-			-			(1	)		-
Ending balance at September 30, 2011	$	18		$	(134	)	$	-		$	230		$	114
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	1		$	70		$	(1	)	$	7		$	77
Uranium:
Beginning balance at January 1, 2011	$	2		$	(a	)	$	(a	)	$	(a	)	$	2
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(4	)		(a	)		(a	)		(a	)		(4	)
Total realized and unrealized gains (losses)		(4	)		(a	)		(a	)		(a	)		(4	)
Settlements		1			(a	)		(a	)		(a	)		1
Ending balance at September 30, 2011	$	(1	)	$	(a	)	$	(a	)	$	(a	)	$	(1	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2011	$	(2	)	$	(a	)	$	(a	)	$	(a	)	$	(2	)

(a) Not applicable.

(b) Net gains and losses on fuel oils 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, including the elimination of financial power contracts between Ameren Illinois and Marketing Company.

47

Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) 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 out of Level 3 into Level 2 for natural gas derivatives were due to management previously using broker quotations to estimate the fair value of natural gas contracts and changing to estimates based upon exchange closing prices without significant unobservable adjustments in the first quarter of 2012. Estimates of fair value based on exchange closing prices are deemed to be a more accurate approximation of natural gas prices. Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were primarily caused by changes in availability of financial trades observable on electronic exchanges between the period ended September 30, 2012, and the previous reporting periods ended June 30, 2012 and December 31, 2011. Any reclassifications are reported as transfers out of Level 3 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, 2012, and 2011, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the three and nine months ended September 30, 2012, and 2011:

	Three Months						Nine Months
	2012			2011			2012			2011
Ameren - derivative commodity contracts:(a)
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils	$	-		$	-		$	2		$	-
Transfers out of Level 3 / Transfers into Level 1 - Fuel oils		1			-			-			-
Transfers out of Level 3 / Transfers into Level 2 - Natural gas		-			-			185			-
Transfers into Level 3 / Transfers out of Level 2 - Power		-			(2	)		1			(1	)
Transfers out of Level 3 / Transfers into Level 2 - Power		(4	)		(2	)		(3	)		-
Net fair value of Level 3 transfers	$	(3	)	$	(4	)	$	185		$	(1	)
Ameren Missouri - derivative commodity contracts:
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils	$	-		$	-		$	2		$	-
Transfers out of Level 3 / Transfers into Level 2 - Natural gas		-			-			15			-
Transfers into Level 3 / Transfers out of Level 2 - Power		-			-			-			(1	)
Transfers out of Level 3 / Transfers into Level 2 - Power		(2	)		-			(4	)		1
Net fair value of Level 3 transfers	$	(2	)	$	-		$	13		$	-
Ameren Illinois - derivative commodity contracts:
Transfers out of Level 3 / Transfers into Level 2 - Natural gas	$	-		$	-		$	170		$	-
Genco - derivative commodity contracts:
Transfers out of Level 3 / Transfers into Level 1 - Fuel oils	$	1		$	-		$	-		$	-

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

The Ameren Companies’ carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. Short-term borrowings, which are composed of Ameren issued commercial paper, also approximate fair value because of their short-term nature. Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. 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, which fair value measurement is considered Level 2 in the fair value hierarchy.

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, 2012, and December 31, 2011:

	September 30, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:(a)(b)
Long-term debt and capital lease obligations (including current portion)	$	6,987	$	8,024	$	6,856	$	7,800
Preferred stock		142		122		142		92
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	4,011	$	4,711	$	3,950	$	4,541
Preferred stock		80		73		80		55
Ameren Illinois:
Long-term debt (including current portion)	$	1,728	$	2,052	$	1,658	$	1,943
Preferred stock		62		49		62		37
Genco:
Long-term debt (including current portion)	$	824	$	790	$	824	$	839

(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.

Put Option Agreement and Guaranty

On March 28, 2012, Genco entered into a put option agreement with AERG. The put option gives Genco the option to sell to AERG all, but not less than all, of the Grand Tower, the Gibson City, and the Elgin energy centers. If Genco exercises the put option, the purchase price for all three energy centers will be the greater of $100 million or the fair

48

market value of the energy centers, as determined by three third-party appraisers in accordance with the terms of the agreement. Upon exercise of the put option, the $100 million minimum purchase price would be payable to Genco within one business day. Genco may exercise the put option at any time through March 28, 2014. The put option may be extended indefinitely for additional one-year periods by agreement of AERG and Genco. If Genco exercises the put option, the closing of the sale of all three energy centers will be subject to the receipt of all necessary regulatory approvals. In exchange for entering into the put option agreement, Genco paid AERG a put option premium of $2.5 million. The put option premium paid by Genco was recorded as an “Other asset” on Genco’s consolidated balance sheet and is being amortized over two years. The amortization expense is eliminated in the consolidation of Ameren’s financial statements.

The put option agreement requires AERG to secure and maintain an Ameren guaranty of payment of contingent obligations under the agreement. Ameren and AERG entered into such a guaranty agreement on March 28, 2012. The guaranty shall remain in effect until either AERG or Ameren satisfies all of the payment obligations under the put option agreement, or the put option agreement is terminated and no further payments are owed by AERG to Genco. As of September 30, 2012, Genco had not exercised the put option.

Intercompany Transfers

In 2012, Genco transferred various assets from its Hutsonville and Meredosia energy centers to AERG. Both of the energy centers were retired in 2011. Genco received cash proceeds in the amount of $3 million. The transfer of the assets was accounted for as a transaction between entities under common control; therefore, Genco did not recognize a gain on the transfer, and upon consolidation Ameren recorded the assets at carrying value.

Electric Power Supply Agreements

During the second quarter of 2012, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2012, through May 31, 2015. Both Marketing Company and Ameren Missouri were among the winning suppliers in the capacity RFP process. In April 2012, Marketing Company contracted to supply a portion of Ameren Illinois’ capacity requirements for less than $1 million and $4 million for the 12 months ending May 31, 2013 and 2015, respectively. In April 2012, Ameren Missouri contracted to supply a portion of Ameren Illinois’ capacity requirements for $1 million and $3 million for the 12 months ending May 31, 2014 and 2015, respectively.

Collateral Postings

Under the terms of the 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 and Marketing Company, as winning suppliers in the RFP process, may be required to post collateral. As of December 31, 2011 and September 30, 2012, there were no collateral postings required of Ameren Missouri or Marketing Company related to the Illinois power procurement agreements.

Marketing Company Sale of Trade Receivables to Ameren Illinois

In accordance with the Illinois Public Utilities Act, Ameren Illinois is required to purchase alternative retail electric suppliers’ receivables relating to Ameren Illinois’ delivery service customers who elected to receive power supply from the alternative retail electric supplier. Beginning in June 2012, Marketing Company sold and Ameren Illinois purchased trade receivables relating to the power supply of residential customers using Marketing Company as their alternative retail electric supplier. Marketing Company has no continuing involvement with or control over the trade receivables after the sale is completed to Ameren Illinois, and neither company has any restrictions on the assets associated with these purchase and sale transactions. As of September 30, 2012, Ameren Illinois’ payable to Marketing Company for the purchase of trade receivables totaled $6 million. For the nine months ended September 30, 2012 Ameren Illinois purchased $17 million of trade receivables from Marketing Company at a discount of less than $1 million. Marketing Company’s receivable from Ameren Illinois as well as Ameren Illinois’ payable to Marketing Company are eliminated in the consolidated Ameren Corporation’s financial statements.

Money Pools

See Note 3 - Short-term Debt and Liquidity for a discussion of affiliate borrowing arrangements.

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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, 2012, and 2011. 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 - Short-term Debt and Liquidity of this report.

			Three Months									Nine Months
Agreement	Income Statement Line Item		Ameren Missouri			Ameren Illinois			Genco			Ameren Missouri			Ameren Illinois			Genco
Genco and EEI power supply	Operating Revenues	2012	$	(a	)	$	(a	)	$	217		$	(a	)	$	(a	)	$	603
agreements with Marketing Company		2011		(a	)		(a	)		289			(a	)		(a	)		771
Ameren Missouri power supply	Operating Revenues	2012		(b	)		(a	)		(a	)		(b	)		(a	)		(a	)
agreements with Ameren Illinois		2011		(b	)		(a	)		(a	)		1			(a	)		(a	)
Ameren Missouri and Ameren Illinois	Operating Revenues	2012		5			(b	)		(a	)		14			1			(a	)
rent and facility services		2011		4			(b	)		(a	)		12			1			(a	)
Ameren Missouri and Genco gas	Operating Revenues	2012		(b	)		(a	)		(b	)		(b	)		(a	)		(b	)
transportation agreement		2011		(b	)		(a	)		(b	)		(b	)		(a	)		(b	)
Transmission services agreement	Operating Revenues	2012		(a	)		5			(a	)		(a	)		11			(a	)
with Marketing Company		2011		(a	)		3			(a	)		(a	)		8			(a	)
Total Operating Revenues		2012	$	5		$	5		$	217		$	14		$	12		$	603
		2011		4			3			289			13			9			771
Ameren Illinois power supply	Purchased Power	2012	$	(a	)	$	83		$	(a	)	$	(a	)	$	243		$	(a	)
agreements with Marketing Company		2011		(a	)		66			(a	)		(a	)		160			(a	)
Ameren Illinois power supply	Purchased Power	2012		(a	)		(b	)		(a	)		(a	)		(b	)		(a	)
agreements with Ameren Missouri		2011		(a	)		(b	)		(a	)		(a	)		1			(a	)
EEI power supply agreement with	Purchased Power	2012		(a	)		(a	)		(b	)		(a	)		(a	)		(b	)
Marketing Company		2011		(a	)		(a	)		24			(a	)		(a	)		36
Total Purchased Power		2012	$	(a	)	$	83		$	(b	)	$	(a	)	$	243		$	(b	)
		2011		(a	)		66			24			(a	)		161			36
Ameren Services support services	Other Operations	2012	$	26		$	22		$	7		$	81		$	67		$	17
agreement	and Maintenance	2011		27			20			4			86			65			14
Insurance premiums(c)	Other Operations	2012		(b	)		(a	)		-			(b	)		(a	)		-
	and Maintenance	2011		(b	)		(a	)		-			(b	)		(a	)		-
Total Other Operations and		2012	$	26		$	22		$	7		$	81		$	67		$	17
Maintenance Expenses		2011		27			20			4			86			65			14
Money pool borrowings (advances)	Interest Charges	2012	$	-		$	(b	)	$	(b	)	$	-		$	(b	)	$	(b	)
		2011		-			-			(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.

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Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at September 30, 2012. 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 United States 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. Missouri 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, 2012. 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, 2012.

	Coal		Natural Gas		Nuclear		Purchased Power (a)		Methane Gas		Other		Total
Ameren:(b)
2012	$	727	$	82	$	22	$	24	$	1	$	110	$	966
2013		871		372		35		420		3		92		1,793
2014		774		243		93		308		3		100		1,521
2015		702		134		86		164		4		61		1,151
2016		685		55		104		78		4		52		978
Thereafter		978		130		346		749		104		246		2,553
Total	$	4,737	$	1,016	$	686	$	1,743	$	119	$	661	$	8,962

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	Coal		Natural Gas		Nuclear		Purchased Power (a)		Methane Gas		Other		Total
Ameren Missouri:
2012	$	614	$	16	$	22	$	3	$	1	$	47	$	703
2013		609		57		35		19		3		54		777
2014		625		43		93		19		3		68		851
2015		614		24		86		19		4		37		784
2016		644		10		104		19		4		28		809
Thereafter		921		36		346		155		104		144		1,706
Total	$	4,027	$	186	$	686	$	234	$	119	$	378	$	5,630
Ameren Illinois:
2012	$	-	$	66	$	-	$	21	$	-	$	8	$	95
2013		-		287		-		401		-		22		710
2014		-		197		-		289		-		22		508
2015		-		108		-		145		-		24		277
2016		-		45		-		59		-		24		128
Thereafter		-		94		-		594		-		102		790
Total	$	-	$	797	$	-	$	1,509	$	-	$	202	$	2,508
Genco:
2012	$	86	$	-	$	-	$	-	$	-	$	31	$	117
2013		177		28		-		-		-		10		215
2014		100		3		-		-		-		7		110
2015		57		2		-		-		-		-		59
2016		10		-		-		-		-		-		10
Thereafter		11		-		-		-		-		-		11
Total	$	441	$	33	$	-	$	-	$	-	$	48	$	522

(a) The purchased power amounts for Ameren and Ameren Illinois include a 20-year agreement for renewable energy credits that was entered into in December 2010 with various renewable energy suppliers. The agreements contain a provision that allows Ameren Illinois to reduce the quantity purchased in the event that Ameren Illinois would not be able to recover the costs associated with the renewable energy credits.

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

Previously, Ameren Illinois entered into an agreement to purchase approximately 15.5 billion cubic feet of synthetic natural gas annually over a 10-year period beginning in 2016 for its natural gas customers. The agreement was entered into pursuant to an Illinois law, which became effective August 2, 2011. Ameren Illinois’ obligations under the agreement were contingent on the counterparty reaching certain milestones during the project development and the construction of the plant that was to produce the synthetic natural gas. The counterparty failed to meet certain milestones during the second quarter of 2012 and, accordingly, the contract was terminated.

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 and natural gas storage, 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, including the Illinois MPS that applies to Genco’s and AERG’s energy centers in Illinois, the EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, Ameren Missouri and Genco, that operate coal-fired energy centers. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards for SO₂ and NO₂ emissions; the CSAPR, which would have required further reductions of SO₂ and NO_x emissions from power plants; a regulation governing management of CCR and coal ash impoundments; the MATS, which requires reduction of emissions of mercury, toxic metals, and acid gases from power plants; revised NSPS for particulate matter, SO₂, and NO_x emissions from new sources; and new regulations under the Clean Water Act that could require significant capital expenditures such as new water intake structures or cooling towers at our energy centers. The EPA has proposed CO₂ limits for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing units in the future. These new and

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proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia in August 2012. 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. If they are, 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 long-lived assets. Failure to comply with environmental laws and regulations might 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, including the CAIR, and our assessment of the potential impacts of the EPA’s proposed regulation for CCR, the finalized MATS, and the revised national ambient air quality standards for SO₂ and NO_x emissions as of September 30, 2012. The estimates for Ameren, Genco and AERG in the table below have decreased from the estimates in the Form 10-K primarily due to the vacated CSAPR and the impacts of the MPS variance granted to AER by the Illinois Pollution Control Board, both of which are discussed below. Additionally, as discussed below, AERG canceled plans for major precipitator upgrades at its E.D. Edwards energy center. The vacated CSAPR did not significantly impact Ameren Missouri’s estimated capital expenditures. 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 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 or modified federal or state requirements;

• further regulation of greenhouse gas emissions;

• revisions to CAIR or reinstatement of CSAPR;

• new national ambient air quality standards or changes to existing standards for ozone, fine particulates, SO₂, and NO_x emissions;

• additional rules governing air pollutant transport;

• finalized regulations under the Clean Water Act;

• finalized regulations classifying CCR as being hazardous or imposing additional requirements on the management of CCR;

• new technology;

• expected power prices;

• variations in costs of material or labor; and

• alternative compliance strategies or investment decisions.

	2012		2013 - 2016					2017 - 2021					Total
AMO(a)	$	55	$	325	-	$	400	$	845	-	$	1,030	$	1,225	-	$	1,485
Genco		130		90	-		110		225	-		250		445	-		490
AERG		5		15	-		25		15	-		25		35	-		55
Ameren	$	190	$	430	-	$	535	$	1,085	-	$	1,305	$	1,705	-	$	2,030

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

The decision to make pollution control equipment investments at our Merchant Generation business depends on whether the expected future market price for power reflects the increased cost for environmental compliance. During early 2012, the observable market price for power for delivery in the current year and in future years sharply declined below 2011 levels primarily because of declining natural gas prices, as well as the impact from the stay of the CSAPR. As a result of this sharp decline in the market price for power, as well as uncertain environmental regulations, Genco decelerated the construction of two scrubbers at its Newton energy center. These scrubbers were originally expected to be installed in late 2013 and early 2014. The ultimate installation of these scrubbers, now estimated to occur by the end of 2019, has been postponed until such time as the incremental investment necessary for completion is justified by visible market conditions. However, Genco will continue to incur capital costs related to the construction of these scrubbers. The table above includes Genco’s estimated costs of approximately $130 million in 2012 and approximately $20 million annually, excluding capitalized interest, from 2013 through 2016 for the construction of the two scrubbers. In addition to Genco’s reduction in estimated capital expenditures, AERG canceled plans for major precipitator upgrades at its E.D. Edwards energy center. AERG is pursuing advanced technology and enhanced operating techniques that have the potential to achieve similar pollution control effects as the precipitator upgrades. Based on the MPS variance granted by the Illinois Pollution Control Board in September 2012, AER is currently scheduled to complete the Newton scrubbers by the end of 2019. See additional information below regarding the MPS variance granted by the Illinois Pollution Control Board.

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

Clean Air Act

Both federal and state laws require significant reductions in SO₂and NO_x emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO₂ and NO_x emissions (the CAIR). The CAIR required generating facilities in 28 states, including Missouri and Illinois, and the District of Columbia, to participate in cap-and-trade programs to reduce annual SO₂emissions, annual NO_x emissions, and ozone season NO_x emissions.

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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 was to become effective on January 1, 2012, for SO₂ and annual NO_x reductions and on May 1, 2012, for ozone season NO_x reductions, with further reductions in 2014. Multiple legal challenges were filed requesting to have CSAPR partially or entirely vacated. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued a stay of the CSAPR. In August 2012, the United States Court of Appeals for the District of Columbia issued a ruling that vacated the CSAPR in its entirety, finding that the EPA exceeded its authority in imposing the CSAPR’s emission limits on states. In October 2012, the EPA filed an appeal of that decision to the full District of Columbia Court of Appeals. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the decision to vacate the CSAPR is overturned.

In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and for the first time require continuous monitoring systems for hydrogen chloride, mercury and particulate matter that are not currently in place. The MATS do not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant; however, emission compliance can be averaged for the entire power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016. Ameren Missouri’s Labadie and Meramec energy centers requested and were granted an extension to comply with the MATS by April 2016.

Separately, on June 14, 2012, the EPA proposed to make more stringent the national ambient air quality standard for fine particulate matter. Under the proposed standard, the EPA and states would develop control measures designed to reduce the emission of fine particulate matter below required levels. Such measures may or may not apply to power plants. The EPA expects to issue a final standard for fine particulate matter by the end of 2012, and require each state to comply with the final standard by 2020, or 2025 if granted an extension of time to achieve compliance. In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standard for ozone. The EPA is required to revisit this standard for ozone again in 2013. The state of Illinois and the state of Missouri will be required to develop attainment plans to comply with the 2008 ambient air quality standards for ozone and are expected to be required to develop attainment plans for fine particulate matter if the new standard is adopted. Ameren, Ameren Missouri and Genco continue to assess the impacts of these new standards.

Ameren Missouri’s current environmental compliance plan for air emissions from its energy centers includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. In July 2011, Ameren Missouri contracted to procure significantly higher volumes of lower-sulfur-content coal than Ameren Missouri’s energy centers have historically burned, which allowed Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO₂ emissions. Currently, Ameren Missouri’s compliance plan assumes the installation of two scrubbers within its coal-fired fleet, mercury control technology, and precipitator upgrades at multiple energy centers during the next 10 years. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the MATS and other recently finalized or proposed EPA regulations.

On September 20, 2012, the Illinois Pollution Control Board granted AER a variance to extend compliance dates for SO₂ emission levels contained in the MPS through December 31, 2019, subject to certain conditions described below. The Illinois Pollution Control Board approved AER’s proposed plan to restrict its SO₂ emissions through 2014 to levels lower than those required by the existing MPS to offset any environmental impact from the variance. The Illinois Pollution Control Board’s order also included the following provisions:

• A schedule of milestones for completion of various aspects of the installation and completion of the scrubber projects at Genco’s Newton energy center; the first milestone relates to the completion of engineering design by July 2015 while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019.

• A requirement for AER to refrain from operating the Meredosia and Hutsonville energy centers through December 31, 2020; however, this restriction does not impact Genco’s ability to make the Meredosia energy center available for any parties that may be interested in repowering one of its units to create an oxy-fuel combustion coal-fired energy center designed for permanent carbon dioxide capture and storage.

AER accepted the terms and conditions of the variance set forth in the order.

Under the MPS, as amended by the recent variance, AER is required to reduce mercury and NO_x emissions by 2015 and SO₂ emissions by the end of 2019. The Illinois Pollution Control Board’s September 2012 variance gives AER additional time for economic recovery and related power price improvements necessary to support scrubber

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installations and other pollution controls at some of AER’s energy centers. To comply with the MPS and other air emissions laws and regulations, Genco and AERG are installing equipment designed to reduce their emissions of mercury, NO_x, and SO₂. Genco and AERG have installed a total of three scrubbers at two energy centers. Two additional scrubbers are being constructed at Genco’s Newton energy center. AER will continue to review and adjust its compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, emission standards required under environmental laws and regulations and compliance technologies, among other factors.

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

Emission Allowances

The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NO_x budget trading program, and the CAIR. Environmental regulations, including those relating to 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 uses the acid rain program’s allowances for SO₂emissions and created annual and ozone season NO_x allowances. Ameren, Ameren Missouri and Genco expect to have adequate CAIR allowances for 2012 to avoid needing to make external purchases to comply with these programs.

Global Climate Change

State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change. Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO₂ emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO₂. The enactment of a climate change law could result in a significant rise in household costs, and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and upon the economy in the Midwest because of the region’s reliance on electricity generated by coal-fired power plants. Natural gas emits about half as much CO₂ as coal 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, economywide 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.

In December 2009, the EPA issued its “endangerment finding” under the Clean Air Act, which stated that greenhouse gas emissions, including CO₂, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 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 the “Tailoring Rule,” which established new higher emission thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants. 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 over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. 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 and whether physical changes or changes in operations subject to the rule occur at our energy centers. In June 2012, the United States Court of Appeals for the District of Columbia upheld the Tailoring Rule.

Separately, on March 27, 2012, the EPA issued the proposed Carbon Pollution Standard for New Power Plants. This proposed NSPS for greenhouse gas emissions would apply only to new fossil-fuel fired electric energy centers and

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therefore does not impact any of Ameren’s, Ameren Missouri’s, or Genco’s existing energy centers. Ameren anticipates this proposed rule, if enacted, could make the construction of new coal-fired energy centers in the United States prohibitively expensive. A final rule is expected in 2012. Any federal climate change legislation that is enacted may preempt the EPA’s regulation of greenhouse gas emissions, including the Tailoring Rule and the Carbon Pollution Standard for New Power Plants, particularly as it relates to power plant greenhouse gas emissions.

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 delay or deny 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 March 2012, the United States District Court for the Southern District of Mississippi dismissed the Comer v. Murphy Oil lawsuit, which alleged CO₂ emissions from several industrial companies, including Ameren Missouri and Genco, created the atmospheric conditions that intensified Hurricane Katrina, thereby causing property damage. The case has been appealed to the appellate court.

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 could result in significant increases in our capital expenditures and operating costs. The compliance costs could be prohibitive at some of our energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.

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.

Commencing in 2005, Genco received a series of information requests from the EPA pursuant to Section 114(a) of the Clean Air Act. The requests 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 August 2012, Genco received a Notice of Violation from the EPA alleging violations of permitting requirements including Title V of the Clean Air Act. The EPA contends that projects performed in 1997, 2006, and 2007 at Genco’s Newton energy center violated federal law. Genco believes its defenses to the allegations described in the Notice of Violation are meritorious. Ameren and Genco are unable to predict the outcome of this matter and whether EPA will address this Notice of Violation administratively or through litigation.

Following the issuance of a Notice of Violation, 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 January 2012, the United States District Court granted, in part, Ameren Missouri’s motion to dismiss various aspects of the EPA’s penalty claims. The EPA’s claims for injunctive relief, including to require the installation of pollution control equipment, remain. 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 Notices 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 penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be incurred.

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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 more than 2 million gallons of water per day from a body of water and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant’s intake screens or to reduce intake velocity to 0.5 feet per second. The proposed rule also requires plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in June 2013, 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, if adopted, 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 energy centers.

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 based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking. It has indicated that it expects to issue a proposed rule in December 2012 and to finalize the rule in May 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 rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003. As part of each transfer, Ameren Illinois contractually agreed to indemnify Genco and AERG for remediation costs associated with pre-existing environmental contamination at the transferred sites.

As of September 30, 2012, Ameren and Ameren Illinois owned or were otherwise responsible for 44 former MGP sites in Illinois. These 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, 2012, Ameren and Ameren Missouri own or are otherwise responsible for 10 former 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, 2012, the estimated probable obligation to remediate these former MGP sites.

	Estimate				Recorded   Liability(a)
	Low		High
Ameren	$	133	$	207	$	133
Ameren Missouri		3		4		3
Ameren Illinois		130		203		130

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

Ameren Illinois is responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of September 30, 2012, 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, 2012, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.

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Ameren Missouri has responsibility for the investigation and potential 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, 2012, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren Missouri recorded a liability of $2 million 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 cleanup and therefore has no recorded liability at September 30, 2012, 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. As of September 30, 2012, Ameren Missouri estimated its obligation at $0.3 million to $10 million. Ameren Missouri recorded a liability of $0.3 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

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 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 affect 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 either to close surface impoundments, such as ash ponds, or to 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, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it 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.

Pumped-storage Hydroelectric Facility Breach

In December 2005, there was a breach of the upper reservoir at Ameren Missouri’s Taum Sauk pumped-storage hydroelectric 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.

Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. As of September 30, 2012, Ameren Missouri had an insurance receivable balance subject to liability coverage of $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

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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. Ameren Missouri filed an appeal of the January 2011 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. In August 2012, the court of appeals remanded the case to the district court for consideration of whether Missouri law voids the alternative dispute resolution provision of the insurance policy. Separately, in April 2012, Ameren Missouri sued a different insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the April 2012 litigation, which is pending 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. The district court has denied the insurer’s motion for dismissal, and the insurer has filed a notice of appeal in the United States Court of Appeals for the Eight Circuit.

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.

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 272 parties named in some pending cases and as few as two in others. In the cases pending as of September 30, 2012, the average number of parties was 80.

The claims filed against Ameren, Ameren Missouri and Ameren Illinois allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Certain former Ameren Illinois energy centers are now owned by either Genco or AERG. As a part of the transfer of energy center ownership in 2000 and 2003, Ameren Illinois contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to each 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, 2012:

Ameren	Ameren Missouri	Ameren Illinois	Genco	Total(a)
4	74	93	(b)	120

(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, 2012, 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, 2012, Ameren, Ameren Missouri, Ameren Illinois and Genco had liabilities of $23 million, $9 million, $14 million, and $- million, respectively, recorded to represent their estimate of their obligations related to asbestos claims.

Ameren Illinois has a tariff rider which permits recovery from customers within IP’s historical service territory of asbestos-related litigation claims that occurred within IP’s historical service territory. The rider can 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 to be recovered from a trust fund that was established when Ameren acquired IP. At September 30, 2012, the trust fund balance was $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 trust 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.

Illinois Sales and Use Tax Exemptions and Credits

InExelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear an appeal of the case, and the decision became final. During the second quarter of 2010, Genco, including EEI, and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The primary 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 used during 2010. EEI is challenging the state of Illinois’ position. In December 2011, EEI filed a request for review by the Informal Conference Board of the Illinois Department of Revenue. Ameren and Genco do not believe that it is probable that the state of Illinois will prevail and therefore have not recorded a

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charge to earnings for the loss contingency. From the second quarter of 2010 through December 31, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $27 million and $19 million, respectively, which represents the maximum potential tax liability to Ameren and Genco, excluding any penalties assessed or interest accrued.

Genco, including EEI, and AERG do not anticipate claiming any additional manufacturing exemptions or credits in 2012, pending discussions with the Illinois Department of Revenue, and therefore will pay sales or use tax on the applicable purchases. Each company, however, is reserving the right to apply for applicable refunds at a later date.

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 operate 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 to 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 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. The government, represented by the DOE, is responsible for 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 both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, the federal government has acknowledged since at least 1994 that it would not meet that deadline. The federal government is not currently predicting when it will begin to meet its disposal obligation. Ameren Missouri has sufficient installed capacity at its 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 current 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. In January 2009, the Obama administration announced that a repository at Yucca Mountain was unworkable and took steps to terminate the Yucca Mountain program, while acknowledging the federal government’s continuing obligation to dispose of utilities’ spent nuclear fuel. In January 2012, an advisory commission established by the DOE issued its report of recommendations for the storage and disposal of spent nuclear fuel. The recommendations covered topics such as the approach to siting future nuclear waste management facilities, the transport and storage of spent fuel and high-level waste, options for waste disposal, institutional arrangements for managing spent nuclear fuel and high-level wastes, and changes needed in the handling of nuclear waste fees and of the Nuclear Waste Fund. Most of these recommendations require action by the DOE and the United States Congress.

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, alleging that the DOE failed to undertake an appropriate fee adequacy review reflecting the current unsettled state of the nuclear waste program. In a June 2012 decision, the court ruled that DOE’s fee adequacy review was legally inadequate and remanded the matter to the DOE. While the court ruled it has the power to direct the DOE to suspend the fee, the court decided that it was premature to do so. Instead, the court ordered the DOE to provide within six months a revised assessment of the amount that should be collected. The DOE’s delay in 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 begin to dispose of the utilities’ spent nuclear fuel and fulfill its contractual obligations, Ameren Missouri and other nuclear power plant owners have also sued DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed a breach of contract lawsuit to recover costs which it would not have incurred had DOE performed its contractual obligations. These costs included the reracking of the Callaway energy center’s spent fuel pool, certain NRC fees, and Missouri ad valorem taxes. In June 2011, the parties reached a settlement that included a payment to Ameren Missouri 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. In March 2012, Ameren Missouri submitted its 2011 costs to the DOE for reimbursement under the settlement agreement. Ameren Missouri expects to receive the 2011 cost reimbursement of $1 million during the fourth quarter of 2012.

In December 2011, Ameren Missouri filed a license extension application with the NRC to extend its Callaway energy center’s operating license from 2024 to 2044. There is no date by which the NRC must act on this application. Among the rules that the NRC has historically relied upon in

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approving license extensions are rules dealing with the storage of spent nuclear fuel at the reactor site and with the NRC’s confidence that permanent disposal of spent nuclear fuel will be available when needed. In a June 2012 decision, the United States Court of Appeals for the District of Columbia Circuit vacated these rules and remanded the case to the NRC, holding that the NRC’s obligations under the National Environmental Policy Act required a more thorough environmental analysis in support of the NRC’s waste confidence decision. In June 2012, a number of groups petitioned the NRC to suspend final licensing decisions in certain NRC licensing proceedings, including the Callaway license extension, until the NRC completed its proceedings on the vacated rules. In August 2012, the NRC stated that it would not issue licenses dependent on the vacated rules until it appropriately addressed the Court’s remand. In September 2012, the NRC directed its staff to issue, within two years, a generic environmental impact statement and a final rule to address the Court’s ruling. The NRC also stated that a site-specific analysis of these issues could be conducted in rare circumstances. 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 by 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 through 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 2011, 2010, and 2009. 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. The last cost study was filed with the MoPSC in September 2011. After considering the results of that cost study and associated financial analysis, Ameren Missouri recommended to the MoPSC that the current rate of deposits to the trust fund continues to be appropriate and does not need to be changed. In the current electric rate case, Ameren Missouri and the MoPSC staff filed a stipulation and agreement which supported keeping the customer contribution level at the current level and recommended approval of the return rates used in Ameren Missouri’s cost study. A decision from the MoPSC is still pending. If Ameren Missouri’s operating license extension application is approved by the NRC, a revised financial analysis will be prepared and the rates charged to customers will be adjusted accordingly to reflect the operating license extension. 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 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 liability.

See Note 2 - Rate and Regulatory Matters for additional information related to the Callaway energy center.

NOTE 11 - ASSET IMPAIRMENTS

We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value, or book value, of such assets may not be recoverable. Under applicable accounting guidance, whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the estimated undiscounted cash flows, we recognize an impairment charge equal to the carrying value of the assets in excess of estimated fair value.

Power prices in the Midwest affect the amount of revenues and cash flows Merchant Generation and Genco can realize by marketing power into the wholesale and retail markets. During the first quarter of 2012, the observable market price for power for delivery in the current year and in future years in the Midwest sharply declined below 2011 levels primarily because of declining natural gas prices and the impact of the stay of the CSAPR. For example, from December 31, 2011, through February 29, 2012, the market price for power at the Indiana Hub for delivery in the current year decreased by 14%. As a result of this sharp decline in the market price of power and the related impact on electric margins, Genco decelerated the construction of two scrubbers at its Newton energy center in February 2012. The sharp decline in the market price of power in the first quarter of 2012 and the related impact on electric margins, as well as the deceleration of construction of Genco’s Newton energy center scrubber project, caused Merchant Generation and Genco to evaluate, during the first quarter of 2012, whether the carrying values of their coal-fired energy centers were recoverable. The carrying values of Merchant Generation’s and Genco’s energy centers exceeded their estimated fair values.

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However, under the applicable accounting guidance, if undiscounted future cash flows from these long-lived assets exceed their carrying values, the assets are deemed unimpaired, and no impairment loss is recognized, even if the carrying values of the assets exceed estimated fair values. Only AERG’s Duck Creek energy center’s carrying value exceeded its estimated undiscounted future cash flows. As a result, Ameren recorded a noncash pretax asset impairment charge of $628 million to reduce the carrying value of AERG’s Duck Creek energy center to its estimated fair value during the first quarter of 2012. This impairment charge was included in Ameren’s results and in the Merchant Generation segment’s results for the first quarter of 2012 and the nine months ended September 30, 2012.

Key assumptions used in the determination of estimated undiscounted cash flows of the Merchant Generation and Genco long-lived assets tested for impairment included the forward price projections for energy and fuel costs, the expected life of the energy center, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a discount rate, were used to estimate the fair value of the long-lived assets of the Duck Creek energy center. The fair value estimate of the long-lived assets of the Duck Creek energy center was based on the income approach, which considers discounted future cash flows. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements.

After the impairment of the Duck Creek energy center, Merchant Generation and Genco believed the carrying value of their energy centers exceeded their estimated fair values by an amount significantly in excess of $1 billion. Merchant Generation and Genco will continue to monitor the market price for power and the related impact on electric margin and other events or changes in circumstances that indicate that the carrying value of their energy centers may not be recoverable as compared to their undiscounted cash flows. Merchant Generation and Genco could recognize additional, material long-lived asset impairment charges in the future as a result of factors outside their control, such as changes in power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of Merchant Generation’s and Genco’s energy centers, and also as a result of factors that may be within their control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell their energy centers.

The Duck Creek energy center asset impairment charge did not result in a violation of any Ameren debt covenants or counterparty agreements.

During the third quarter of 2011, the MoPSC issued an electric rate order that 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 the amount recovered from property insurance. Consequently, Ameren and Ameren Missouri each reported a pretax charge to earnings of $89 million. Also during 2011, Resources Company announced that a total of four units at Genco’s Meredosia and Hutsonville energy centers would cease operations 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. See Note 1 - Summary of Significant Accounting Policies for information regarding the intangible asset impairment recorded in 2011.

NOTE 12 - RETIREMENT BENEFITS

Ameren’s pension and postretirement plans are funded in compliance with income tax regulations and to meet federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at December 31, 2011, its estimated investment performance through September 30, 2012, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $150 million in each of the next five years, with aggregate estimated contributions of $560 million. These amounts are estimates which may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.

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The following table presents the components of the net periodic benefit cost for Ameren’s pension and postretirement benefit plans for the three and nine months ended September 30, 2012, and 2011:

	Pension Benefits(a)												Postretirement Benefits(a)
	Three Months						Nine Months						Three Months						Nine Months
	2012			2011			2012			2011			2012			2011			2012			2011
Service cost	$	21		$	19		$	62		$	57		$	6		$	6		$	18		$	17
Interest cost		43			45			128			135			13			15			39			44
Expected return on plan assets		(53	)		(54	)		(160	)		(162	)		(15	)		(14	)		(44	)		(41	)
Amortization of:
Transition obligation		-			-			-			-			1			1			2			2
Prior service cost (benefit)		(1	)		-			(2	)		(1	)		(2	)		(2	)		(5	)		(6	)
Actuarial loss		19			10			58			31			2			1			6			3
Curtailment loss		2			-			2			-			(b	)		-			(b	)		-
Net periodic benefit cost	$	31		$	20		$	88		$	60		$	5		$	7		$	16		$	19

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

(b) Less than $1 million.

As discussed in Note 1 - Summary of Significant Accounting Policies, EEI substantially completed an employee reduction program during the third quarter of 2012. The employee reduction resulted in a curtailment of EEI’s pension and management postretirement benefit plans, which are separate from Ameren’s pension and postretirement benefit plans. The EEI curtailment resulted in a curtailment loss of $2 million, which was included in Ameren’s and Genco’s “Other operations and maintenance” expenses on their consolidated statements of income for the three and nine months ended September 30, 2012.

Separately, in 2012, EEI’s pension plan was amended to adjust the calculation of the future benefit obligation for all of its active employees from a traditional, final pay formula to a cash balance formula. This plan amendment resulted in a $6 million benefit obligation reduction and a corresponding offset to accumulated other comprehensive income. Additionally, in 2012, EEI’s management and labor union postretirement medical benefit plans were amended to adjust for moving to a Medicare Advantage plan. This plan amendment triggered a remeasurement of the benefit obligation as of September 30, 2012. This plan amendment and remeasurement resulted in a net $70 million benefit obligation reduction with a corresponding offset to accumulated other comprehensive income as of September 30, 2012. The impact of these EEI plan amendments were reflected in Ameren’s consolidated statement of comprehensive income and Genco’s consolidated statement of income (loss) and comprehensive income (loss) for the three and nine months ended September 30, 2012.

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, 2012, and 2011:

	Pension Costs								Postretirement Costs
	Three Months				Nine Months				Three Months				Nine Months
	2012		2011		2012		2011		2012		2011		2012		2011
Ameren Missouri	$	16	$	13	$	48	$	39	$	2	$	3	$	7	$	8
Ameren Illinois		9		4		27		12		1		3		3		9
Genco(a)		4		1		9		6		2		1		6		2
Other		2		2		4		3		-		-		-		-
Ameren(a)(b)	$	31	$	20	$	88	$	60	$	5	$	7	$	16	$	19

(a) Includes EEI’s pension and management postretirement benefit plans’ $2 million curtailment loss recognized in the third quarter of 2012 as a result of its employee reduction program.

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

NOTE 13 - SEGMENT INFORMATION

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

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The following table presents information about the revenues and specified items included in Ameren’s net income for the three and nine months ended September 30, 2012, and 2011, and total assets as of September 30, 2012, and December 31, 2011.

Three Months	Ameren Missouri		Ameren Illinois		Merchant Generation			Other			Intersegment Eliminations			Consolidated
2012:
External revenues	$	1,059	$	642	$	299		$	1		$	-		$	2,001
Intersegment revenues		5		6		83			1			(95	)		-
Net income (loss) attributable to Ameren Corporation(a)		236		71		20			47	(b)		-			374
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
Nine Months
2012:
External revenues	$	2,583	$	1,924	$	809		$	3		$	-		$	5,319
Intersegment revenues		16		12		242			3			(273	)		-
Net income (loss) attributable to Ameren Corporation(a)		400		130		(348	)		-			-			182
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
As of September 30, 2012:
Total assets	$	12,967	$	7,227	$	3,240		$	1,125		$	(1,061	)	$	23,498
As of December 31, 2011:
Total assets	$	12,757	$	7,213	$	3,833		$	1,211		$	(1,369	)	$	23,645

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

(b) The increase in net income attributable to Ameren Corporation in Other primarily relates to an increase in income tax benefit as a result of the reversal of the income tax benefit reduction recognized in conjunction with the first quarter 2012 long-lived asset impairment of Merchant Generation’s Duck Creek energy center. The income tax benefit reduction resulted from the requirement under authoritative accounting guidance to recognize interim income tax expense (benefit) using the annual estimated effective tax rate and fully reversed over the first nine months of 2012.

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.

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. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.

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

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

• AER consists of non-rate-regulated operations, including Genco, AERG and Marketing Company. Genco operates a merchant electric generation business in Illinois and holds an 80% ownership interest in EEI, which it consolidates for financial reporting purposes.

The financial statements of Ameren and Genco are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per share.

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OVERVIEW

Ameren reported net income of $374 million for the third quarter of 2012, compared with net income of $285 million for the third quarter of 2011. Ameren also reported net income of $182 million for the nine months ended September 30, 2012, compared with net income of $494 million for the nine months ended September 30, 2011. Earnings in the third quarter and first nine months of 2012 benefited from the absence in 2012 of charges recorded in 2011 at Ameren Missouri, as a result of the MoPSC’s July 2011 order that disallowed costs of enhancements relating to the rebuilding of Ameren Missouri’s Taum Sauk energy center in excess of amounts recovered from property insurance, and at Merchant Generation, as a result of the closure of the Meredosia and Hutsonville energy centers. Earnings in the third quarter and first nine months of 2012 were also favorably impacted by higher utility rates at Ameren Missouri and Ameren Illinois, favorable net unrealized MTM activity, and a reduction in operations and maintenance expenses at both Ameren Missouri and Merchant Generation energy centers primarily as a result of fewer outages. In addition, earnings in the third quarter of 2012 benefited from a noncash change in income tax benefit, related to the 2012 Merchant Generation asset impairment discussed below, resulting from the requirement to recognize interim period income tax expense using the annual estimated effective tax rate. These positive factors were offset during the third quarter and first nine months of 2012, in part, by lower earnings at Ameren Illinois reflecting the impacts of formula ratemaking at Ameren Illinois, including the impact of the ICC’s September 2012 electric delivery service rate order, and lower electric margins in the Merchant Generation segment due to lower power prices and higher fuel and transportation costs. In addition, Ameren’s earnings in the nine months ended September 30, 2012, were lower than the prior-year period, because of a noncash asset impairment charge in the Merchant Generation segment, which reduced pretax earnings by $628 million.

Both Ameren Missouri and Ameren Illinois have pending electric rate cases that are nearing completion with orders expected from their state regulators in the fourth quarter of 2012 and with rates becoming effective in early January 2013. Ameren Missouri is seeking an increase in annual revenues of $323 million, which includes the recovery of costs associated with energy efficiency programs under the MEEIA, which was approved earlier this year. In this rate case, Ameren Missouri requested that the MoPSC approve the implementation of a storm cost tracking mechanism, as well as plant-in-service accounting treatment, both of which would be enhancements to the existing regulatory framework in Missouri. The MoPSC has several important issues to consider in this case. Those issues include determining the appropriate return on equity, Ameren Missouri’s request for the implementation of a storm cost tracking mechanism and plant-in-service accounting treatment, Ameren Missouri’s request for recovery of its 2011 severance costs, and whether Ameren Missouri should be able to continue to employ its existing FAC, including all of the transmission costs currently included within the FAC, at the current 95% sharing level.

In September 2012, the ICC issued an order in Ameren Illinois’ initial IEIMA filing approving an electric delivery service revenue requirement of $779 million, which is a $55 million decrease from the electric delivery service revenue requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The initial filing rates became effective on October 19, 2012, and will be effective through the end of 2012. Ameren Illinois has appealed the ICC order to the appellate court. Ameren Illinois believes that the ICC misapplied Illinois law, including through the use of an average rate base as opposed to a year-end rate base, the treatment of accumulated deferred income taxes, the method for calculating the equity portion of Ameren Illinois’ capital structure, and the method for calculating interest on the revenue requirement reconciliation. The ICC’s September 2012 order jeopardizes Ameren Illinois’ ability to implement the infrastructure improvements to the extent and on the timetable envisioned in the IEIMA. Until the uncertainty surrounding how the Illinois law will ultimately be implemented is removed, Ameren Illinois is reducing its IEIMA capital spending with a corresponding negative effect on the job creation that the legislature sought to achieve with the law. Ameren Illinois expects to reduce or defer a total of $30 million of its previously planned 2013 electric distribution capital expenditures. Earlier in 2012, Ameren Illinois filed an update filing based on 2011 costs and expected net plant additions for 2012, which would result in a $17 million increase in annual electric delivery service revenues from the amount allowed in the ICC initial rate order. In the update filing proceeding, the ICC staff and the administrative law judges are recommending a reduction to Ameren Illinois’ annual electric delivery service revenues.

Progress continues to be made in Ameren’s efforts to increase its investment in electric transmission. An important step for the Illinois Rivers project, which is a MISO-approved regional multi-value project, occurred on November 7, 2012, when ATXI filed with the ICC for a certificate of public convenience and necessity for the approximately 400-mile transmission line route. A decision from the ICC on the certificate is expected in July 2013. This certificate will allow ATXI to acquire right of way for the transmission line. ATXI received FERC approval with respect to the Illinois Rivers project for use of a for a forward-looking rate calculation with an annual reconciliation adjustment and other rate mechanisms.

In September 2012, the Illinois Pollution Control Board granted AER a variance to extend compliance dates for SO2 emission levels contained in the MPS through December 31, 2019, subject to certain conditions. The Illinois Pollution Control Board approved AER’s proposed plan to restrict its SO2 emissions through 2014 to levels lower than those required by the existing MPS to offset any environmental impact from the variance. The Illinois Pollution Control Board’s order established a schedule of milestones for completion of various aspects of the installation and completion of the scrubber projects at Genco’s Newton energy center. The Illinois Pollution Control Board’s September 2012 variance gives AER additional time for economic recovery and related power price improvements necessary to support scrubber installations and other pollution controls at some of AER’s energy centers. Further, the Merchant Generation segment decreased its estimated environmental capital expenditures for 2012 through 2016 by $35 million, from those estimates in the Form 10-K, primarily due to the vacated CSAPR and the impacts of the MPS variance.

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

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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. Ameren Illinois’ electric delivery service utility business, pursuant to the IEIMA, conducts an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for that year, with recoveries from or refunds to customers in a subsequent year. Included in Ameren’s Illinois’ revenue requirement reconciliation is a formula for the return on equity, which is equal to the average for the applicable calendar year of the monthly average yields of 30-year United States Treasury bonds plus 590 basis points for 2012 and 580 basis points thereafter. Therefore, Ameren Illinois’ annual return on equity will be directly correlated to yields on United States Treasury bonds. Fluctuations in interest rates and conditions in the capital and credit markets also affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our energy centers and transmission and distribution systems and the level of purchased power costs, operations and maintenance costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.

Earnings Summary

Net income attributable to Ameren Corporation increased to $374 million, or $1.54 per share, in the third quarter of 2012, from $285 million, or $1.18 per share, in the third quarter of 2011. Net income attributable to Ameren Corporation in the third quarter of 2012 increased in the Ameren Missouri segment and in the Merchant Generation segment by $46 million and $29 million, respectively, from the prior-year period. Net income attributable to Ameren Corporation in the third quarter of 2012 decreased in the Ameren Illinois segment by $27 million from the prior-year period.

Net income attributable to Ameren Corporation decreased to $182 million, or 75 cents per share, in the first nine months of 2012, from $494 million, or $2.05 per share, in the first nine months of 2011. The decrease in the net income attributable to Ameren Corporation in the first nine months of 2012 was primarily caused by a net loss in the Merchant Generation segment of $348 million compared with net income in the Merchant Generation segment of $26 million in the prior-year period. Net income attributable to Ameren Corporation in the first nine months of 2012 decreased in the Ameren Illinois segment by $38 million from the prior-year period and increased in the Ameren Missouri segment by $99 million from the prior-year period.

Earnings were favorably impacted in the third quarter and first nine months of 2012, compared with the same periods in 2011, by:

• the absence in 2012 of charges recorded in 2011 at Ameren Missouri for the MoPSC’s July 2011 disallowance of costs of enhancements relating to the rebuilding of Ameren Missouri’s Taum Sauk energy center in excess of amounts recovered from property insurance and at Merchant Generation for the closure of the Meredosia and Hutsonville energy centers (32 cents per share in both periods);

• higher utility rates at Ameren Missouri and Ameren Illinois. Ameren Missouri’s electric rates increased pursuant to an order issued by the MoPSC, which became effective in July 2011. The favorable impact of the Ameren Missouri rate increase on earnings was reduced by the increased regulatory asset amortization directed by the rate order. Ameren Illinois’ natural gas rates increased pursuant to an order issued by the ICC, which became effective in mid-January 2012 (6 cents per share and 21 cents per share, respectively);

• reduction in operations and maintenance expenses at both Ameren Missouri and Merchant Generation energy centers due to fewer outages and a reduction in employees (2 cents per share and 8 cents per share, respectively); and

• favorable net unrealized MTM activity primarily related to nonqualifying power hedges and fuel-related contracts as well as favorable changes in the market value of investments used to support Ameren’s deferred compensation plans (10 cents per share and 7 cents per share, respectively).

In addition to the above items favorably impacting both periods, earnings were favorably impacted in the third quarter of 2012, compared with the same period in 2011, by:

• an increase in income tax benefit as a result of the reversal of the income tax benefit reduction recognized in conjunction with the first quarter 2012 long-lived asset impairment of Merchant Generation’s Duck Creek energy center (18 cents per share). The income tax benefit reduction was required by authoritative accounting guidance, which requires that interim income tax expense (benefit) should be computed at an estimated annual effective tax rate, and was fully reversed over the first nine months of 2012; and

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• the impact of warmer weather conditions on electric demand (1 cent per share) as compared to a hot summer in 2011. As discussed below, a portion of favorable electric weather conditions experienced within Ameren Illinois’ service territory during the third quarter were offset by the IEIMA’s collar adjustment on earnings.

In addition to the above items favorably impacting both periods, earnings were favorably impacted in the first nine months of 2012, compared with the same period in 2011, by:

• the impact of fewer major storms on operations and maintenance expenses (9 cents per share);

• a reduction in Ameren Missouri’s purchased power expense and an increase in interest income as a result of a FERC-ordered refund received in June 2012 from Entergy for a power purchase agreement that expired in 2009 (7 cents per share); and

• the absence in 2012 of a 2011 reduction to revenues as a result of the MoPSC’s April 2011 FAC review order covering 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 previously recognized sales (5 cents per share).

Earnings were negatively impacted in the third quarter and first nine months of 2012, compared with the same periods in 2011, by:

• lower electric margins in the Merchant Generation segment, largely due to reduced generation volumes caused by lower market prices for power as well as higher fuel and related transportation costs (10 cents per share and 25 cents per share, respectively); and

• a reduction in Ameren Illinois’ electric earnings reflecting the IEIMA revenue requirement reconciliation adjustment, collar adjustment on earnings, and required donations (12 cents per share in both periods). The downward adjustment to earnings in the third quarter was caused by revised expectations for full-year 2012 recoverable costs as a result of lower expected spending levels and the impacts of the ICC’s September 2012 order in Ameren Illinois’ initial rate filing. The reduction in earnings for the nine-month period was primarily caused by a lower allowed return on equity as the ICC’s 2010 electric rate order resulted in a higher return on equity than the 2012 formula rate calculation allowed.

In addition to the above items negatively impacting both periods, earnings were negatively impacted in the first nine months of 2012, compared with the same period in 2011, by:

• the 2012 long-lived asset impairment of Merchant Generation’s Duck Creek energy center due to the sharp decline in the market price of power in the first quarter of 2012 ($1.55 per share); and

• the impact of mild winter weather conditions on electric and natural gas demand (9 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 2011. For further details regarding the Ameren Companies’ results of operations for the third quarter and first nine months of 2012 and 2011, including explanations of Margins, Other Operations and Maintenance, Asset Impairments 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.

Below is a table of income statement components by segment for the three and nine months ended September 30, 2012, and 2011:

	Ameren Missouri			Ameren Illinois			Merchant Generation			Other / Intersegment Eliminations			Total
Three Months 2012:
Electric margin	$	817		$	312		$	151		$	(4	)	$	1,276
Natural gas margin		13			77			-			-			90
Other revenues		-			-			-			-			-
Other operations and maintenance		(203	)		(159	)		(67	)		5			(424	)
Depreciation and amortization		(111	)		(55	)		(19	)		(3	)		(188	)
Taxes other than income taxes		(87	)		(24	)		(5	)		(3	)		(119	)
Other income and (expenses)		11			-			-			(1	)		10
Interest charges		(55	)		(34	)		(25	)		1			(113	)
Income (taxes) benefit		(148	)		(46	)		(15	)		51			(158	)

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	Ameren Missouri			Ameren Illinois			Merchant Generation			Other / Intersegment Eliminations			Total
Net income	$	237		$	71		$	20		$	46		$	374
Noncontrolling interest and preferred dividends		(1	)		-			-			1			-
Net income attributable to Ameren Corporation	$	236		$	71		$	20		$	47		$	374
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		(218	)		(152	)		(72	)		10			(432	)
Goodwill, impairment and other charges		(89	)		-			(36	)		1			(124	)
Depreciation and amortization		(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
Nine Months 2012:
Electric margin	$	1,898		$	828		$	412		$	(8	)	$	3,130
Natural gas margin		52			270			-			(1	)		321
Other revenues		1			-			-			(1	)		-
Other operations and maintenance		(611	)		(513	)		(203	)		18			(1,309	)
Asset impairment		-			-			(628	)		-			(628	)
Depreciation and amortization		(328	)		(165	)		(79	)		(10	)		(582	)
Taxes other than income taxes		(236	)		(94	)		(19	)		(7	)		(356	)
Other income and (expenses)		37			(10	)		-			(2	)		25
Interest charges		(167	)		(98	)		(73	)		-			(338	)
Income (taxes) benefit		(243	)		(86	)		237			10			(82	)
Net income (loss)		403			132			(353	)		(1	)		181
Noncontrolling interest and preferred dividends		(3	)		(2	)		5			1			1
Net income (loss) attributable to Ameren Corporation	$	400		$	130		$	(348	)	$	-		$	182
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		(682	)		(501	)		(217	)		32			(1,368	)
Goodwill, impairment and other charges		(89	)		-			(38	)		1			(126	)
Depreciation and amortization		(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

Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and natural gas margins in the three months and nine months ended September 30, 2012, compared with the same periods in 2011. 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 Missouri			Ameren Illinois			Genco		Other(a)		Ameren
Electric revenue change:
Effect of weather (estimate)(b)	$	(1	)	$	3		$	-	$	-	$	2
Regulated rates:
Base rates (estimate)		23			-			-		-		23
Formula ratemaking adjustment under IEIMA (estimate)		-			(47	)		-		-		(47	)

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Three Months	Ameren Missouri			Ameren Illinois			Genco			Other(a)			Ameren
Recovery of FAC under-recovery(c)	$	(16	)	$	-		$	-		$	-		$	(16	)
Off-system revenues included in base rates		(40	)		-			-			-			(40	)
Transmission services		1			-			-			-			1
Illinois pass-through power supply costs		-			(46	)		-			(16	)		(62	)
Rate-regulated sales volume (excluding the impact of abnormal weather)		(14	)		(4	)		-			-			(18	)
Wholesale revenues		(2	)		-			-			-			(2	)
Merchant Generation sales volume		-			-			(97	)		(8	)		(105	)
Merchant Generation sales price changes, including hedge effect		-			-			(13	)		4			(9	)
Net unrealized MTM gains (losses)		(1	)		-			2			5			6
Other		(3	)		(1	)		(1	)		5			-
Total electric revenue change	$	(53	)	$	(95	)	$	(109	)	$	(10	)	$	(267	)
Fuel and purchased power change:
Fuel:
Merchant Generation production volume and other	$	-		$	-		$	42		$	2		$	44
Fuel, purchased power and transportation costs included in base rates		39			-			-			-			39
Recovery of FAC under-recovery(c)		16			-			-			-			16
Net unrealized MTM gains		-			-			13			6			19
Price – Merchant Generation		-			-			(8	)		(2	)		(10	)
Merchant Generation purchased power and other		-			-			36			(2	)		34
Illinois pass-through power supply costs		-			46			-			16			62
Total fuel and purchased power change	$	55		$	46		$	83		$	20		$	204
Net change in electric margins	$	2		$	(49	)	$	(26	)	$	10		$	(63	)
Natural gas margins change:
Base rates (estimate)	$	-		$	5		$	-		$	-		$	5
Bad debt rider		-			(1	)		-			-			(1	)
Sales volume and other		1			2			-			(1	)		2
Net change in natural gas margins	$	1		$	6		$	-		$	(1	)	$	6
Nine months
Electric revenue change:
Effect of weather (estimate)(b)	$	(26	)	$	(1	)	$	-		$	-		$	(27	)
Regulated rates:
Base rates (estimate)		102			-			-			-			102
Formula ratemaking adjustment under IEIMA (estimate)		-			(35	)		-			-			(35	)
Recovery of FAC under-recovery(c)		(48	)		-			-			-			(48	)
Off-system revenues included in base rates		(108	)		-			-			-			(108	)
FAC prudence review disallowance		17			-			-			-			17
Transmission services		1			(9	)		-			-			(8	)
Illinois pass-through power supply costs		-			(101	)		-			(81	)		(182	)
Energy efficiency and environmental remediation cost riders		-			4			-			-			4
Rate-regulated sales volume (excluding the impact of abnormal weather)		(14	)		(7	)		-			-			(21	)
Wholesale revenues		(13	)		-			-			-			(13	)
Merchant Generation sales volume		-			-			(196	)		5			(191	)
Merchant Generation sales price changes, including hedge effect		-			-			(28	)		(9	)		(37	)
Net unrealized MTM gains		-			-			3			15			18
Other		1			(3	)		(1	)		4			1
Total electric revenue change	$	(88	)	$	(152	)	$	(222	)	$	(66	)	$	(528	)
Fuel and purchased power change:
Fuel:
Merchant Generation production volume and other	$	-		$	-		$	84		$	4		$	88
Fuel, purchased power and transportation costs included in base rates		85			-			-			-			85
Recovery of FAC under-recovery(c)		48			-			-			-			48
Net unrealized MTM losses		-			-			(8	)		(1	)		(9	)
Price – Merchant Generation		-			-			(18	)		(7	)		(25	)
Power purchase agreement settlement		24			-			-			-			24
Merchant Generation purchased power and other		-			-			54			2			56
Illinois pass-through power supply costs		-			101			-			81			182
Total fuel and purchased power change	$	157		$	101		$	112		$	79		$	449
Net change in electric margins	$	69		$	(51	)	$	(110	)	$	13		$	(79	)
Natural gas margins change:
Effect of weather (estimate)(b)	$	(3	)	$	(12	)	$	-		$	-		$	(15	)
Base rates (estimate)		1			14			-			-			15
Rate redesign		(5	)		-			-			-			(5	)
Energy efficiency programs and environmental remediation cost riders		-			4			-			-			4
Bad debt rider		-			(2	)		-			-			(2	)
Sales volume (excluding impact of abnormal weather) and other		1			5			-			-			6
Net change in natural gas margins	$	(6	)	$	9		$	-		$	-		$	3

(a) Includes amounts for nonregistrant subsidiaries (largely made up of other Merchant Generation) and intercompany eliminations.

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(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 periods based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories.

(c) Represents the change in the net recovery of fuel costs under the FAC recovered through customer rates, with corresponding offsets to fuel expense representing the amortization of a previously recorded regulatory asset.

Ameren Corporation

Ameren’s electric margins decreased by $63 million, or 5%, and $79 million, or 2%, for the three and nine months ended September 30, 2012, respectively, compared with the same periods in 2011. The following items had an unfavorable impact on Ameren’s electric margins for the three and nine months ended September 30, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Decreased utilization of Merchant Generation’s energy centers, primarily due to lower spot market prices, resulted in a decline in sales volume ($105 million and $191 million, respectively). This decline was mitigated by a related decrease in production volume and other costs ($44 million and $88 million, respectively) and a decrease in purchased power and other costs ($34 million and $56 million, respectively.)

• Decreased revenues at Ameren Illinois due to the formula ratemaking adjustment related to an annual reconciliation of the revenue requirement pursuant to the IEIMA. The downward adjustment to revenues in the third quarter was caused by revised expectations for full-year 2012 recoverable costs as a result of lower expected spending levels and the impacts of the ICC’s September 2012 order in Ameren Illinois’ initial rate filing. The reduction in revenues for the nine-month period was primarily caused by a lower allowed return on equity as the ICC’s 2010 electric rate order resulted in a higher return on equity than the 2012 formula rate calculation allowed. The formula for the return on equity is equal to the average for the applicable calendar year of the monthly average yields of 30-year United States Treasury bonds plus 590 basis points for 2012. The return on equity included in Ameren Illinois’ 2010 electric rate order was 10.2% whereas the IEIMA formula for 2012 is projected to result in an 8.8% return on equity with the ability to earn above or below this amount by 50 basis points. With hot summer weather, this formula return on equity cap came into effect limiting expected 2012 return on equity at 9.3% ($47 million and $35 million, respectively). See Note 2 - Rate and Regulatory Matters under Part 1, Item 1, of this report for further information.

• Winter weather conditions in 2012 were mild compared to somewhat colder-than-normal conditions in 2011, as evidenced by a 29% decrease in heating degree-days, which decreased revenues by $27 million for the nine months ended September 30, 2012, compared with the same period in 2011.

• Higher fuel prices in the Merchant Generation segment, primarily due to higher commodity and transportation rates associated with new coal supply agreements ($10 million and $25 million, respectively).

• Excluding the estimated impact of abnormal weather, rate-regulated sales volumes were flat for both periods; however, margins decreased due to declines in the higher-margin residential and commercial sectors ($18 million and $21 million, respectively).

• The inclusion of wholesale sales in Ameren Missouri’s FAC as an offset to fuel costs beginning July 31, 2011 ($2 million and $13 million, respectively).

• Lower transmission revenues primarily at Ameren Illinois due to timing of the recovery of prior-period expenses ($8 million for the nine months ended September 30, 2012, compared with the same period in 2011).

The following items had a favorable impact on Ameren’s electric margins for the three and nine months ended September 30, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Higher electric base rates at Ameren Missouri, effective July 2011 ($23 million and $102 million, respectively), offset by an increase in net base fuel expense ($1 million and $23 million, respectively), which was a result of higher net base fuel cost rates approved in the 2011 MoPSC rate order. Net base fuel expense is the sum of fuel, purchased power and transportation costs included in base rates (+$39 million and +$85 million, respectively) and off-system revenues (-$40 million and -$108 million, respectively) in the above table. See below for additional details regarding the FAC.

• Reduced purchased power expense at Ameren Missouri as a result of a FERC-ordered refund received in June 2012 from Entergy relating to a power purchase agreement that expired in 2009 ($24 million for the nine months ended September 30, 2012). See Note 2 - Rate and Regulatory Matters under Part 1, Item 1, of this report for further information.

• Absence in 2012 of a reduction in Ameren Missouri’s revenues, recorded in 2011 resulting from the MoPSC’s order with respect to its FAC prudence review disallowance for the period from March 1, 2009, to September 30, 2009 ($17 million for the nine months ended September 30, 2012). See Note 2 - Rate and Regulatory Matters under Part 1, Item 1, of this report for further information.

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• Net unrealized MTM activity, principally at the Merchant Generation segment, related to nonqualifying power hedges and fuel-related contracts ($25 million and $9 million, respectively).

• Summer weather conditions in 2012 were comparable to a very hot 2011, as evidenced by a 3% increase in cooling degree-days. However, weather conditions in Ameren’s service territory in 2012 were warmer than normal as evidenced by 21% more cooling degree-days.

Ameren’s revenues associated with Illinois pass-through power supply costs decreased because of lower power prices on sales and customers switching to alternative retail electric suppliers. These revenues were offset by a corresponding net decrease in purchased power expense ($62 million and $182 million, respectively).

Ameren Missouri has a FAC cost recovery mechanism that allows Ameren Missouri to recover, through customer rates, 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, greater or less than the amount set in base rates, without a traditional rate proceeding. Ameren Missouri accrues, as a regulatory asset, fuel and purchased power costs that are greater than the amount set in base rates (FAC under-recovery). Net recovery of the FAC under-recovery decreased $16 million and $48 million for the three and nine months ended September 30, 2012, respectively, compared with the same periods in 2011, with corresponding offsets to fuel expense to amortize the previously recognized FAC regulatory asset.

Ameren’s natural gas margins increased by $6 million, or 7%, and $3 million, or 1%, for the three and nine months ended September 30, 2012, respectively, compared with the same periods in 2011. The following items had a favorable impact on Ameren’s natural gas margins for the three and nine months ended September 30, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Increase in natural gas rates effective February 2011 at Ameren Missouri and January 2012 at Ameren Illinois ($5 million and $15 million).

• Excluding the estimated impact of abnormal weather, retail sales volumes increased 13% and 3%, respectively, at Ameren Illinois, driven largely by lower-margin industrial customers ($2 million and $5 million, respectively).

• Net increased recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms at Ameren Illinois, which increased revenues by $4 million for the nine months ended September 30, 2012, compared with the same period in 2011. See Other Operations and Maintenance Expenses 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’s natural gas margins for the three and nine months ended September 30, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Winter weather conditions in 2012 were mild compared to somewhat colder-than-normal conditions in 2011, as evidenced by a decrease in heating degree-days of 29%, which decreased margins $15 million for the nine months ended September 30, 2012, compared with the same period in 2011.

• Rate redesign at Ameren Missouri, as a result of the natural gas delivery service rate order that became effective in February 2011, allowed Ameren Missouri to recover more of its non-PGA residential revenues through a fixed monthly charge, with the remaining amounts recovered based on sales volumes, which resulted in revenues being recovered more evenly throughout the year. Revenues decreased $5 million for the nine months ended September 30, 2012, compared with the same period in 2011, due to this rate redesign not being in effect for the first two months of 2011.

Ameren Missouri

Ameren Missouri has a FAC cost recovery mechanism, which is outlined in the Ameren margin section above.

Ameren Missouri’s electric margins increased by $2 million, or less than 1%, and $69 million, or 4%, for the three and nine months ended September 30, 2012, respectively, compared with the same periods in 2011. The following items had a favorable impact on Ameren Missouri’s electric margins for the three and nine months ended September 30, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Higher electric base rates, effective in July 2011 ($23 million and $102 million, respectively), partially offset by an increase in net base fuel expense ($1 million and $23 million, respectively), which was a result of higher net base fuel cost rates approved in the 2011 MoPSC rate order. Net base fuel expense is the sum of fuel, purchased power and transportation costs included in base rates (+$39 million and +$85 million, respectively) and off-system revenues (-$40 million and -$108 million, respectively) in the above table.

• Reduced purchased power expense as a result of a FERC-ordered refund received in June 2012 from Entergy relating to a power purchase agreement that expired in 2009 ($24 million for the nine months ended September 30, 2012, compared to the same period in 2011). See Note 2 - Rate and Regulatory Matters under Part 1, Item 1, of this report for further information.

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• Absence in 2012 of a reduction in revenues in 2011 resulting from the MoPSC’s order with respect to its FAC prudence review disallowance for the period from March 1, 2009, to September 30, 2009 ($17 million for the nine months ended September 30, 2012, compared to the same period in 2011). See Note 2 - Rate and Regulatory Matters under Part 1, Item 1, of this report for further information.

• Summer weather conditions in 2012 were comparable to a very hot 2011, as evidenced by a 3% increase in cooling degree-days. However, weather conditions in Ameren Missouri’s service territory in 2012 were warmer than normal as evidenced by 20% more cooling degree-days.

The following items had an unfavorable impact on Ameren Missouri’s electric margins for the three and nine months ended September 30, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Winter weather conditions in 2012 were mild compared to somewhat colder-than-normal conditions in 2011, as evidenced by a 32% decrease in heating degree-days, which decreased revenues by $26 million for the nine months ended September 30, 2012, compared with the same period in 2011.

• Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes declined by 2% and 1%, respectively, attributable to energy efficiency measures and customer conservation efforts ($14 million for both periods).

• The inclusion of wholesale sales in the FAC as an offset to fuel costs beginning July 31, 2011 ($2 million and $13 million, respectively).

Ameren Missouri’s natural gas margins increased by $1 million, or 8%, for the three months ended September 30, 2012, compared with the same period in 2011; however, natural gas margins decreased by $6 million, or 10%, for the nine months ended September 30, 2012, compared with the same period in 2011. The following items had an unfavorable impact on Ameren Missouri’s natural gas margins for the three and nine months ended September 30, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Rate redesign, as a result of the natural gas delivery service rate order that became effective in February 2011, allowed Ameren Missouri to recover more of its non-PGA residential revenues through a fixed monthly charge, with the remaining amounts recovered based on sales volumes, which resulted in revenues being recovered more evenly throughout the year. Revenues decreased by $5 million for the nine months ended September 30, 2012, compared with the same period in 2011, due to this rate redesign not being in effect for the first two months of 2011.

• Winter weather conditions in 2012 were mild compared to somewhat colder-than-normal conditions in 2011, as evidenced by a decrease in heating degree-days of 32% for the nine months ended September 30, 2012, compared with the same period in 2011, which decreased margins $3 million.

Ameren Missouri’s natural gas margins were favorably impacted for the nine months ended September 30, 2012, compared to the same period in 2011, by an increase in rates effective February 2011 ($1 million).

Ameren Illinois

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, electric revenues and offsetting purchased power expenses may fluctuate, primarily because of customer switching to alternative retail electric suppliers and their usage. Ameren Illinois does not generate earnings based on the resale of power but rather on the delivery of energy.

Ameren Illinois’ electric margins decreased by $49 million, or 14%, and $51 million, or 6%, for the three and nine months ended September 30, 2012, respectively, compared with the same periods in 2011. The following items had an unfavorable impact on Ameren Illinois’ electric margins for the three and nine months ended September 30, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Decreased revenues due to the formula ratemaking adjustment related to an annual reconciliation of the revenue requirement pursuant to the IEIMA. The downward adjustment to revenues in the third quarter was caused by revised expectations for full-year 2012 recoverable costs as a result of lower expected spending levels and the impacts of the ICC’s September 2012 order in Ameren Illinois’ initial rate filing. The reduction in revenues for the nine-month period was primarily caused by a lower allowed return on equity as the ICC’s 2010 electric rate order resulted in a higher return on equity than the 2012 formula rate calculation allowed. The formula for the return on equity is equal to the average for the applicable calendar year of the monthly average yields of 30-year United States Treasury bonds plus 590 basis points for 2012. The return on equity included in Ameren Illinois’ 2010 electric rate order was 10.2% whereas the IEIMA formula for 2012 is projected to result in an 8.8% return on equity with the ability to earn above

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or below this amount by 50 basis points. With hot summer weather, this formula return on equity cap came into effect limiting expected 2012 return on equity at 9.3% ($47 million and $35 million, respectively). See Note 2 - Rate and Regulatory Matters under Part 1, Item 1, of this report for further information.

• Lower transmission revenues due to timing of the recovery of prior period expenses ($9 million for the nine months ended September 30, 2012, compared with the same period in 2011).

• Excluding the estimated impact of abnormal weather, rate-regulated sales volumes increased by 1% for both periods, driven largely by the lower-margin industrial sector; however, margins decreased due to declines in the higher-margin residential and commercial sectors ($4 million and $7 million, respectively).

The following items had a favorable impact on Ameren Illinois’ electric margins for the three and nine months ended September 30, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Weather conditions in the third quarter of 2012 were warmer than the same period in 2011, as evidenced by a 4% increase in cooling degree-days, which increased revenues by $3 million.

• Net increased recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms, which increased revenues by $4 million for the nine months ended September 30, 2012, compared with the same period in 2011. See Other Operations and Maintenance Expenses in this section for information on the related offsetting increase in energy efficiency and environmental remediation costs.

Ameren Illinois’ natural gas margins increased by $6 million, or 8%, and $9 million, or 3%, for the three and nine months ended September 30, 2012, respectively, compared with the same periods in 2011. The following items had a favorable impact on Ameren Illinois’ natural gas margins for the three and nine months ended September 30, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Increase in natural gas rates effective January 2012 ($5 million and $14 million, respectively).

• Excluding the estimated impact of abnormal weather, retail sales volumes increased 13% and 3%, respectively, driven largely by the lower-margin industrial sector ($2 million and $5 million, respectively).

• Net increased recovery of energy efficiency program costs and environmental remediation costs through Illinois cost recovery mechanisms, which increased revenues by $4 million for the nine months ended September 30, 2012, compared with the same period in 2011. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.

Ameren Illinois’ natural gas margins were unfavorably affected by winter weather conditions in 2012 that were mild compared to somewhat colder-than-normal conditions in 2011, as evidenced by a decrease in heating degree-days of 28%, which decreased margins $12 million for the nine months ended September 30, 2012, compared with the same period in 2011.

Merchant Generation

Merchant Generation’s electric margins decreased by $15 million, or 9%, and $97 million, or 19%, for the three and nine months ended September 30, 2012, respectively, compared with the same periods in 2011. See below for explanations of electric margin variances for the Merchant Generation segment.

Genco

Genco’s electric margins decreased by $26 million, or 21%, and $110 million, or 30%, for the three and nine months ended September 30, 2012, respectively, compared with the same periods in 2011. The following items had an unfavorable impact on electric margins for the three and nine months ended September 30, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Decreased energy center utilization at Genco, primarily due to lower spot market prices and an EEI sales contract in 2011 that was not supplied in 2012. Consequently, Genco’s sales volume declined ($97 million and $196 million, respectively), which was mitigated by a related decline in production volume and other costs ($42 million and $84 million, respectively) and a decrease in purchased power and other costs ($36 million and $54 million, respectively). Genco’s average capacity factor decreased to 62% and 61%, respectively, in 2012, compared with 79% and 71%, respectively, in 2011, because of lower power prices. Genco’s equivalent availability factor decreased to 89% in the third quarter of 2012, compared with 92% in the third quarter of 2011. Genco’s equivalent availability factor increased to 85% year-to-date in 2012, compared with 84% year-to-date in 2011.

• Lower revenues under EEI’s power supply agreement with Marketing Company (EEI PSA) due to lower spot market prices ($7 million and $32 million, respectively). In addition, Genco’s electric margins were unfavorably affected under its power supply agreement with Marketing Company (Genco PSA) by lower contract prices for physical hedges in the third quarter of 2012

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partially offset by a settlement with a customer ($6 million). However, the revenues for the first nine months of 2012 were favorably impacted as a higher portion of spot sales were financially hedged at prices that represented a premium to the spot market when compared with the same period in 2011 ($4 million). The combined price impact on Genco of both power supply agreements reduced revenues by $13 million and $28 million, respectively.

• Higher fuel prices, primarily due to higher commodity and transportation rates associated with new coal supply agreements ($8 million and $18 million, respectively).

• Net unrealized MTM activity primarily on fuel-related contracts decreased margins $5 million for the nine months ended September 30, 2012, when compared with the same period in 2011.

Genco’s electric margins were favorably affected by net unrealized MTM activity primarily on fuel-related contracts, which increased margins $15 million, for the three months ended September 30, 2012, when compared with the same period in 2011.

Other Merchant Generation

Electric margins from Ameren’s other Merchant Generation operations, primarily AERG and Marketing Company, increased by $11 million, or 24%, and $13 million, or 9%, for the three and nine months ended September 30, 2012, respectively, compared with the same periods in 2011. The following items had a favorable impact on electric margins for the three and nine months ended September 30, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Net unrealized MTM activity, principally at Marketing Company, related to nonqualifying power hedges and fuel-related contracts ($11 million and $14 million, respectively).

• Higher average sales prices under AERG’s power supply agreement (AERG PSA) with Marketing Company due to a settlement with a customer, which increased revenues by $4 million for the third quarter of 2012, compared with the same period in 2011.

• Increased energy center utilization at AERG for the nine months ended September 30, 2012, compared with the same period in 2011, due to increased availability. AERG’s higher production volume resulted in an increase in sales volume ($5 million), which was mitigated by an increase in related production volume and other costs ($5 million). AERG’s average capacity factor increased to 76%, in 2012 compared to 75% in 2011. AERG’s equivalent availability factor increased to 86% in 2012 compared with 81% in 2011.

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, 2012, compared with the year-ago periods (except where a specific period is referenced):

• Lower average sales prices under AERG’s power supply agreement (AERG PSA) with Marketing Company, due to lower spot market prices, decreased revenues by $9 million, for the nine months ended September 30, 2012, compared with the same period in 2011.

• Lower energy center utilization at AERG for the third quarter of 2012, compared with the same period in 2011, due to decreased availability. AERG’s lower production volume resulted in a decline in sales volume ($8 million), which was mitigated by a decline in related production volume and other costs of $2 million. AERG’s average capacity factor decreased to 78%, in 2012 compared with 84% in 2011. AERG’s equivalent availability factor decreased to 87% in 2012 compared with 91% in 2011.

• Higher fuel prices, primarily due to higher commodity and transportation rates associated with new coal supply agreements ($2 million and $7 million, respectively).

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren Corporation

Three months - Other operations and maintenance expenses were $8 million lower in the third quarter of 2012, as compared with the third quarter of 2011.

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

• A $12 million favorable change in unrealized net MTM gains between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.

• An $8 million decrease in plant maintenance costs, primarily due to fewer major boiler outages.

• A $7 million decrease in other plant maintenance costs, primarily due to the December 2011 closure of two coal-fired energy centers in the Merchant Generation segment.

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• A $3 million decrease in non-storm-related distribution maintenance expenditures, due to unfavorable summer weather preventing crews from completing planned maintenance projects.

• Disciplined cost management efforts to align spending with regulatory outcomes and economic conditions.

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

• A $7 million increase in other labor costs, primarily because of staff additions at Ameren Illinois due to the requirements of the IEIMA.

• A $6 million charge in 2012 for a canceled project at Ameren Missouri.

• A $5 million increase in other transmission and distribution expenses, primarily at Ameren Illinois because of National Electric Safety Code repairs, which are nonrecoverable operating expenditures under formula ratemaking pursuant to the IEIMA.

• A $4 million increase in outside legal fees.

Nine months - Other operations and maintenance expenses were $59 million lower in the first nine months of 2012, as compared with the first nine months of 2011.

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

• A $35 million decrease in storm-related repair costs, due to fewer major storms in 2012.

• A $26 million decrease in plant maintenance costs, primarily due to fewer major boiler outages and a reduction in energy center headcount.

• A $14 million favorable change in unrealized net MTM gains between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.

• A $13 million decrease in other plant maintenance costs, primarily due to the December 2011 closure of two coal-fired energy centers at the Merchant Generation segment.

• A $10 million decrease in bad debt expense due to a reduction in uncollectible expense of $3 million at Ameren Missouri and adjustments under the Ameren Illinois bad debt rider of $7 million. Expenses recorded under the Ameren Illinois bad debt rider mechanism are recovered through customer billings, and, accordingly, are offset by increased revenues, with no overall effect on net income.

• Disciplined cost management efforts to align spending with regulatory outcomes and economic conditions.

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

• A $17 million charge in 2012 for canceled projects.

• An $8 million increase in energy efficiency and environmental remediation costs at Ameren Illinois. These costs are recovered through customer billings and, accordingly, are offset by increased revenues, with no overall impact on net income.

• A $6 million increase in other transmission and distribution expenses, primarily at Ameren Illinois because of National Electric Safety Code repairs, which are nonrecoverable operating expenditures under formula ratemaking pursuant to the IEIMA.

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, 2012, compared with the same periods in 2011, were as follows:

Ameren Missouri

Three months - Other operations and maintenance expenses decreased by $15 million.

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

• An $8 million decrease in plant maintenance costs, primarily due to fewer major boiler outages.

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

• A $4 million decrease in employee benefit costs, primarily because of adjustments under the pension and postretirement benefit cost tracker, which is a regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred under GAAP and the level of such costs built into electric rates. Accordingly, these costs are offset by changes in base rate revenues, with no overall impact on net income.

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• A $2 million decrease in non-storm-related distribution maintenance expenditures, due to unfavorable summer weather preventing crews from completing planned maintenance projects.

• Disciplined cost management efforts to align spending with regulatory outcomes and economic conditions.

Other operations and maintenance expenses increased between periods because of a $6 million charge in 2012 for a canceled project.

Nine months - Other operations and maintenance expenses decreased by $71 million.

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

• A $20 million decrease in storm-related repair costs, due to fewer major storms in 2012.

• An $18 million decrease in plant maintenance costs, primarily due to fewer major boiler outages and a reduction in energy center headcount.

• A $12 million decrease in employee benefit costs, primarily because of adjustments in rates under the pension and postretirement benefit cost tracker.

• An $11 million reduction in other labor costs, primarily because of staff reductions.

• A $7 million decrease in non-storm-related distribution maintenance expenditures due to lower inspection spending.

• A $7 million favorable change in unrealized net MTM gains between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.

• Disciplined cost management efforts to align spending with regulatory outcomes and economic conditions.

Other operations and maintenance expenses increased between periods because of a $6 million charge in 2012 for a canceled project.

Ameren Illinois

Three months - Other operations and maintenance expenses increased by $7 million.

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

• A $5 million increase in other transmission and distribution expenses, primarily because of National Electric Safety Code repairs, which are nonrecoverable operating expenditures under formula ratemaking pursuant to the IEIMA.

• A $4 million increase in other labor costs, primarily because of staff additions due to the requirements of the IEIMA.

Other operations and maintenance expenses decreased between periods because of a $3 million favorable change in unrealized net MTM gains 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 increased by $12 million.

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

• An $11 million increase in non-storm-related distribution maintenance expenditures due, in part, to favorable winter weather in 2012 allowing crews to complete more maintenance projects.

• An $8 million increase in energy efficiency and environmental remediation costs.

• An $8 million increase in other labor costs, primarily because of staff additions due to the requirements of the IEIMA.

• An $8 million increase in other transmission and distribution expenses, primarily because of National Electric Safety Code repairs, which are nonrecoverable operating expenditures under formula ratemaking pursuant to the IEIMA.

• A $3 million increase in employee benefit costs, primarily due to increased pension expense.

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

• A $15 million decrease in storm-related repair costs, due to fewer major storms in 2012.

• A $7 million decrease in bad debt expense, including adjustments under the bad debt rider.

• A $4 million favorable change in unrealized net MTM gains between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.

Merchant Generation

Three months - Other operations and maintenance expenses decreased by $5 million in the Merchant Generation segment due to reduced plant maintenance costs as a result of the December 2011 closure of two coal-fired energy centers and fewer outages.

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Nine months - Other operations and maintenance expenses decreased by $14 million in the Merchant Generation segment, as reduced plant maintenance costs of $21 million, due to the December 2011 closure of two coal-fired energy centers and fewer outages, more than offset charges for canceled projects of $11 million.

Genco

Three months - Other operations and maintenance expenses decreased by $7 million at Genco, due to reduced plant maintenance costs as a result of the December 2011 closure of two coal-fired energy centers and fewer outages.

Nine months - Other operations and maintenance expenses decreased by $4 million at Genco because plant maintenance costs decreased by $17 million as a result of the December 2011 closure of two coal-fired energy centers and fewer outages. Partially offsetting decreased plant maintenance costs were prior-period gains from property sales of $12 million and charges for canceled projects in the current period of $4 million.

Asset Impairments and Other Charges

Merchant Generation

In the first quarter of 2012, Ameren recognized a noncash pretax impairment charge of $628 million to reduce the carrying value of AERG’s Duck Creek energy center to its estimated fair value. During the first quarter of 2012, the observable market price of power for delivery in the current year and in future years in the Midwest declined sharply below 2011 levels primarily because of declining natural gas prices and the impact of the stay of the CSAPR. As a result of this sharp decline in the market price of power and the related impact on electric margins, Genco decelerated the construction of two scrubbers at its Newton energy center in 2012. The sharp decline in the market price of power in the first quarter of 2012 and the related impact on electric margins, as well as the deceleration of construction of Genco’s Newton energy center scrubber project, caused Merchant Generation and Genco to evaluate during the first quarter of 2012 whether the carrying values of their coal-fired energy centers were recoverable. See Note 1 - Summary of Significant Accounting Policies and Note 11 - Asset Impairment to our financial statements under Part I, Item I, of this report for additional information regarding the Duck Creek energy center impairment recorded in 2012 and impairments recorded in 2011.

Depreciation and Amortization

Ameren Corporation

Three months - Depreciation and amortization expenses were $8 million lower in the third quarter of 2012, as compared with the third quarter of 2011, primarily because decreases in the Merchant Generation segment that were partially offset by increases at Ameren Missouri.

Nine months - Depreciation and amortization expenses were $3 million lower in the first nine months of 2012, as compared with the first nine months of 2011, primarily because of decreases in the Merchant Generation segment and a $5 million reduction in depreciation and amortization expense at Ameren Services, due to the retirement of computer equipment in 2011, that were partially offset by increases at Ameren Missouri and Ameren Illinois.

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, 2012, compared with the same periods in 2011, were as follows:

Ameren Missouri

Three and nine months - Depreciation and amortization expenses increased by $9 million and $28 million, respectively, primarily because of increased depreciation and amortization expense associated with the scrubbers at the Sioux energy center (depreciation expense began with the effective date of the July 2011 electric rate order) and other capital additions.

Ameren Illinois

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

Nine months - Depreciation and amortization expenses increased by $4 million, primarily due to transmission and distribution infrastructure additions.

Merchant Generation

Three and nine months - Depreciation and amortization expenses decreased by $17 million and $30 million, respectively, because of a change in estimate of asset retirement obligations and the closure of two coal-fired energy centers in December 2011 at Genco. Additionally, the asset impairment recorded during the first quarter of 2012 caused a reduction in the carrying value of the Duck Creek energy center’s net plant assets.

Genco

Three and nine months - Depreciation and amortization expenses decreased by $9 million and $12 million, respectively, primarily due to a change in estimate of asset retirement obligations and the closure of two coal-fired energy centers in December 2011.

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Taxes Other Than Income Taxes

Ameren Corporation

Three months - Taxes other than income taxes were comparable between periods, as decreases at Ameren Illinois offset increases at Ameren Missouri.

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

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, 2012, compared with the same periods in 2011, were as follows:

Ameren Missouri

Three months - Taxes other than income taxes increased by $2 million due to higher property taxes resulting from increased state and local assessments in 2012 and the recording of a $2 million refund for protested distributable taxes in the prior-year period. The increase was partially offset by a decrease in gross receipts taxes as a result of decreased sales.

Nine months - Taxes other than income taxes were comparable between periods as higher property taxes resulting from increased state and local assessments in 2012 and the recording of a refund for protested distributable taxes in the prior-year period offset a decrease in payroll taxes.

Ameren Illinois

Three months - Taxes other than income taxes decreased by $5 million, primarily due to an electric distribution tax refund that was received in the third quarter of 2012.

Nine months - Taxes other than income taxes were comparable between periods, primarily because a reduction in gross receipts taxes as a result of decreased sales offset higher property taxes, due to increased rates.

Merchant Generation and Genco

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

Other Income and Expenses

Ameren Corporation

Three months - Other income, net of expenses, decreased by $3 million in the third quarter of 2012, as compared with the third quarter of 2011, primarily due to increased donation expenses at Ameren Missouri.

Nine months - Other income, net of expenses, decreased by $11 million in the first nine months of 2012, as compared with the first nine months of 2011, primarily due to increased expenses at Ameren Illinois as discussed below.

Variations in other income, net of expenses, in Ameren’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2012, compared with the same periods in 2011, were as follows:

Ameren Missouri

Three months - Other income, net of expenses, decreased by $3 million, primarily due to increased donations.

Nine months - Other income, net of expenses, was comparable between periods. An increase in interest income, resulting from the interest paid by Entergy on the amount it overcharged Ameren Missouri under a power purchase agreement offset increased donations. See Note 2 - Rate and Regulatory Matters under Part I, Item I, of this report for further information on the power purchase agreement with Entergy.

Ameren Illinois

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

Nine months - Ameren Illinois had net other expenses of $10 million in the first nine months of 2012, compared with net other income of $1 million in the first nine months of 2011. Donations increased by $10 million because of a one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and a $1 million annual donation for customer assistance programs pursuant to the IEIMA, as a result of Ameren Illinois participating in the formula ratemaking process.

Merchant Generation and Genco

Three and nine months - Other income, net of expenses, was comparable between periods in the Merchant Generation segment and at Genco.

Interest Charges

Ameren Corporation

Three months - Interest charges were comparable between periods.

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Nine months - Interest charges were comparable between periods as an increase in interest charges at Ameren Missouri was offset by decreases at Ameren Illinois and in the Merchant Generation segment. In addition, reduced credit facility borrowings and commercial paper issuances at Ameren lowered interest charges.

Variations in interest charges in Ameren’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2012, compared with the same periods in 2011, were as follows:

Ameren Missouri

Three months - Interest charges were comparable between periods.

Nine months - Interest charges increased by $14 million, primarily because of an increase in interest charges associated with uncertain tax positions.

Ameren Illinois

Three months - Interest charges were comparable between periods.

Nine months - Interest charges decreased by $5 million, primarily because of the redemption of $150 million of senior secured notes in June 2011.

Merchant Generation

Three months - Interest charges were comparable between periods.

Nine months - Interest charges decreased by $7 million in the Merchant Generation segment, primarily because of increased capitalized interest due to the Newton energy center scrubber project at Genco.

Genco

Three and nine months - Interest changes decreased by $2 million and $7 million, respectively, primarily because of increased capitalized interest due to the Newton energy center scrubber project.

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, 2012, and 2011:

	Three Months						Nine Months
	2012			2011			2012			2011
Ameren(a)		30	%		36	%		31	%		37	%
Ameren Missouri(a)		38			35			38			35
Ameren Illinois(a)		39			40			39			40
Genco(b)		45			20			33			44
Merchant Generation(a)		43			10			40			45

(a) The provision for income taxes was based on the current estimate of the annual effective tax rate adjusted to reflect the tax impact of items discrete to the relevant period.

(b) The provision for income taxes for the three and nine months ended September 30, 2012, was based on the actual effective tax rate for the interim period. Authoritative accounting guidance provides that the actual effective rate is acceptable for interim periods if a reliable estimate of the annual effective tax rate is not determinable. As a result of the relationship between projected “Income Before Income Taxes” and “Income Taxes” for Genco for the year ended December 31, 2012, a reliable estimate of the annual 2012 effective tax rate could not be made.

Ameren Corporation

Three months - The effective tax rate in the third quarter of 2012 was lower than the third quarter of 2011 primarily due to the partial reversal of the first quarter reduction of the income tax benefit recognized in conjunction with the asset impairment in the Merchant Generation segment. This reduction in the recognized tax benefit fully reversed over the first nine months of 2012.

Nine months - The effective tax rate in the first nine months of 2012 was lower than the same period in 2011 primarily due to a lower projected annual effective tax rate. For interim reporting purposes, authoritative accounting guidance requires that tax expense related to ordinary income must be computed using an estimated annual effective tax rate. Ameren’s projected annual effective tax rate of 31% is lower than the statutory rate primarily as a result of (i) lower projected full-year pretax income due to the large impairment charge recorded in the first quarter of 2012 and (ii) relatively consistent permanent differences as compared to the prior period, which are expected to be larger in 2012 as a percentage of pretax income than in prior years. This unfavorable reduction in the effective tax rate was partially offset by the impact of investment tax credit amortization and favorable amortization of property-related regulatory assets and liabilities on a lower pretax book income in the current year as compared to the same period a year ago.

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Variations in effective tax rates in Ameren’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2012, compared with the same periods in 2011, were as follows:

Ameren Missouri

Three and nine months - The effective tax rate was higher primarily due to a reduction in the amortization of property-related regulatory assets and liabilities. Additionally, the effective tax rate increased because of a higher reserve for uncertain tax positions in 2012, compared to a lower reserve in 2011.

Ameren Illinois

Three months - The effective tax rate was lower primarily due to the increased impact of favorable net amortization of property-related regulatory assets and liabilities and tax credits on lower pretax income in 2012 compared with the same period in 2011.

Nine months - The effective tax rate was lower primarily due to favorable net amortization of property-related regulatory assets and liabilities in 2012 compared with unfavorable amortization in 2011, along with the increased impact of tax credits and permanent book tax differences on lower pretax income in the current period, offset by the favorable impact of recording the adjustment to deferred tax assets in the prior-year period due to the Illinois statutory income tax rate increase in 2011.

Merchant Generation

Three months - The effective rate was higher in the Merchant Generation segment primarily due to the impact of the manufacturing deduction in the year ago period.

Nine months - The effective tax rate was lower primarily due to the unfavorable impact of recording an adjustment to deferred tax liabilities in the prior-year period due to the Illinois statutory income tax rate increase in 2011, along with the impact of the manufacturing deduction, which was partially offset by favorable changes in the reserves for uncertain tax position in the year-ago period.

Genco

Three months - The effective tax rate was higher primarily due to the impact of the manufacturing deduction in the prior period.

Nine months - The effective tax rate was lower primarily due to the impact of permanent items on lower pretax book income in 2012 compared to the year-ago period.

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. In addition to using cash flows from operating activities, Ameren, Ameren Missouri and Ameren Illinois 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. Ameren, Ameren Missouri and Ameren Illinois 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 Missouri and Ameren Illinois, with equity infusions from Ameren. Ameren, Ameren Missouri and Ameren Illinois 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, achieve IEIMA performance metrics, and other improvements. Ameren intends to finance those capital expenditures and investments in its rate-regulated businesses with a blend of equity and debt so that it maintains a capital structure 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, fund scheduled debt maturities, and maintain financial strength and flexibility.

Genco, through Marketing Company, sells power through primarily market-based contracts with wholesale and retail customers to generate operating cash flows. Genco and the Merchant Generation segment seek to fund their operations internally and therefore seek not to rely on financing from Ameren or external, third-party sources. Genco and the Merchant Generation segment will continue to seek to defer or reduce capital and operating expenses, sell certain assets, and take other actions as necessary to fund their operations internally while maintaining safe and reliable operations. Under its indenture, Genco may not borrow additional funds from external, third-party sources if its interest coverage ratio is less than a specified minimum or its

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leverage ratio is greater than a specified maximum. See Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report for additional information on Genco’s indenture provisions. Based on projections as of September 30, 2012, of its operating results and cash flows, Genco expects that, by the end of the first quarter of 2013, its interest coverage ratio will be less than the minimum ratio required for the company to borrow additional funds from external, third-party sources. Genco’s indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren’s control, and if a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time. In March 2012, Genco entered into a put option agreement with AERG, for the potential sale of the Grand Tower, the Gibson City, and the Elgin energy centers, in order to provide an additional source of liquidity, if needed in the future. See Note 8 - Related Party Transactions, in Part I, Item 1, of this report for additional information regarding the put option agreement and Ameren’s guaranty of AERG’s contingent obligations under the put option agreement.

The following table presents net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2012, and 2011:

	Net Cash Provided By Operating Activities							Net Cash (Used In) Investing Activities									Net Cash (Used In) Financing Activities
	2012		2011		Variance			2012			2011			Variance			2012			2011			Variance
Ameren(a)	$	1,361	$	1,565	$	(204	)	$	(1,011	)	$	(751	)	$	(260	)	$	(307	)	$	(837	)	$	530
Ameren Missouri		748		854		(106	)		(570	)		(459	)		(111	)		(247	)		(241	)		(6	)
Ameren Illinois		441		437		4			(304	)		(206	)		(98	)		(65	)		(437	)		372
Genco		111		179		(68	)		(94	)		(101	)		7			-			(76	)		76

(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 decreased in the first nine months of 2012, compared with the first nine months of 2011. The following items contributed to the decrease in cash from operating activities during the first nine months of 2012, compared with the same period in 2011:

• Cash flows associated with Ameren Missouri’s under-recovered FAC costs decreased by $148 million as recoveries outpaced deferrals in 2011 by $95 million while deferrals outpaced recoveries in 2012 by $53 million.

• The premiums paid to debtholders in connection with the repurchase of the tendered principal of multiple series of Ameren Missouri and Ameren Illinois senior secured notes totaled $138 million. See Note 4 - Long-Term Debt and Equity Financings under Part I, Item 1, of this report for additional information.

• A $110 million decrease in cash collections from customer receivables, excluding the impacts of the receipt of funds from, and deposits into, court registries discussed separately below, primarily caused by milder weather in December 2011, compared with December 2010.

• Income tax payments of $2 million in 2012, compared with income tax refunds of $53 million in 2011. The 2011 refund resulted primarily from an IRS settlement, while the 2012 payment was caused by the purchase of state tax credits. Ameren did not make any material federal income tax payments in either period because of accelerated deductions authorized by economic stimulus legislation, use of its net operating loss carryforwards, and other deductions.

• Electric and natural gas margins, as discussed in Results of Operations, decreased by $50 million, excluding impacts of noncash MTM transactions and Ameren Illinois’ noncash IEIMA formula ratemaking adjustment.

• During 2012, coal inventory increased by $45 million primarily due to additional tons held in Ameren Missouri’s inventory because generation levels were below expected levels due to market conditions, the absence in 2012 of flooding that impeded coal deliveries in 2011, and milder weather conditions in early 2012.

• An $18 million increase in energy efficiency expenditures, primarily for Ameren Illinois customer programs that are recovered through customer billings over time.

• A net $14 million reduction in previously posted collateral returned from counterparties due primarily to the items discussed at the registrant subsidiaries below and a decrease in collateral returned by Ameren (parent) and Marketing Company counterparties of $5 million due to changes in the market prices of power.

• Ameren Illinois made a one-time $7.5 million payment to the Illinois Science and Energy Innovation Trust as required by the IEIMA.

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The following items partially offset the decrease in Ameren’s cash from operating activities during the first nine months of 2012, compared with the same period in 2011:

• A $111 million decrease in pension and postretirement plan contributions. In 2011, Ameren Illinois contributed to Ameren’s postretirement benefit plan trust an incremental $100 million in excess of Ameren Illinois’ annual postretirement net periodic cost for regulatory purposes.

• Ameren Missouri’s receipt of a total of $37 million from the Stoddard County Circuit Court’s registry and the Cole County Circuit Court’s registry as the MoPSC’s 2009 and 2010 electric rate orders were upheld on appeals. Additionally, $21 million fewer Ameren Missouri receivables were paid into the court registries in 2012 in connection with the electric rate order appeals. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for additional information.

• A $44 million decrease in the cost of natural gas held in storage because of lower prices.

• A $34 million decrease in major storm restoration costs.

• A $27 million increase in the MISO liability due, in part, to fewer payments required for December 2011 purchases compared to the payments required for December 2010 purchases.

• A $15 million increase in over-recovered Ameren Illinois’ electric purchased power commodity costs.

• A $12 million decrease in employee medical plan payments due to fewer active employees following the staff reduction completed in the fourth quarter of 2011.

• An $11 million decrease in taxes other than income tax payments primarily caused by the timing of property tax payments for Ameren Missouri.

• The receipt of $9 million for net coal transfers to refiners under agreements, primarily for the Merchant Generation segment, that did not exist during the first nine months of 2011. The coal will be purchased back from the refiners in a subsequent period.

Ameren Missouri

Ameren Missouri’s cash from operating activities decreased in the first nine months of 2012, compared with the first nine months of 2011. The following items contributed to the decrease in cash from operating activities during the first nine months of 2012, compared with the same period in 2011:

• Cash flows associated with the under-recovered FAC costs decreased by $148 million as recoveries outpaced deferrals in 2011 by $95 million while deferrals outpaced recoveries in 2012 by $53 million.

• The premiums paid to debtholders for the repurchase of the tendered principal of multiple series of senior secured notes totaled $62 million.

• A $51 million increase in income tax payments primarily due to a reduction in depreciation deductions for tax purposes along with an increase in income from a litigation settlement.

• During 2012, coal inventory increased by $51 million primarily due to additional tons held in inventory because generation levels were below expected levels due to market conditions, the absence in 2012 of flooding that impeded coal deliveries in 2011, and milder weather conditions in early 2012.

• A $35 million decrease in cash collections from customer receivables, excluding the impacts of the receipt of funds from, and deposits into, court registries discussed separately below, primarily caused by milder weather in December 2011, compared with December 2010.

• A net $5 million increase in collateral posted with counterparties due, in part, to changes in the market price of power.

The following items partially offset the decrease in Ameren Missouri’s cash from operating activities during the first nine months of 2012, compared with the same period in 2011:

• Electric and natural gas margins, as discussed in Results of Operations, increased by $63 million, excluding impacts of noncash MTM transactions.

• Receipt of a total of $37 million from the Stoddard County Circuit Court’s registry and the Cole County Circuit Court’s registry as the MoPSC’s 2009 and 2010 electric rate orders were upheld on appeals. Additionally, $21 million fewer Ameren Missouri receivables were paid into the court registries in 2012 in connection with the electric rate order appeals.

• A $19 million decrease in major storm restoration costs.

• A $13 million decrease in property tax payments caused primarily by the timing of such property tax payments.

• An $11 million reduction in energy efficiency expenditures.

• A $7 million decrease in pension and postretirement plan contributions.

• A $6 million decrease in employee medical plan payments due to fewer active employees following the staff reduction completed in the fourth quarter of 2011.

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Ameren Illinois

Ameren Illinois’ cash from operating activities increased in the first nine months of 2012 compared with the first nine months of 2011. The following items contributed to the increase in cash from operating activities during the first nine months of 2012, compared with the same period in 2011:

• A $100 million decrease in pension and postretirement plan contributions. In 2011, Ameren Illinois contributed to Ameren’s postretirement benefit plan trust an incremental $100 million in excess of Ameren Illinois’ annual postretirement net periodic cost for regulatory purposes.

• A $41 million decrease in the cost of natural gas held in storage because of lower prices.

• A $32 million increase in income tax refunds primarily caused by an increase in accelerated depreciation deductions authorized by economic stimulus legislation.

• A $27 million increase in the MISO liability due, in part, to fewer payments required for December 2011 purchases compared to the payments required for December 2010 purchases.

• A $15 million increase in over-recovered electric purchased power commodity costs.

• A $15 million decrease in major storm restoration costs.

• An $8 million increase in receipts from Genco caused by an acceleration of the deferred intercompany tax gain caused by the closure of the Meredosia and Hutsonville energy centers.

The following items partially offset the increase in Ameren Illinois’ cash from operating activities during the first nine months of 2012, compared with the same period in 2011:

• An $81 million decrease in cash collections from customer receivables, primarily caused by milder weather in December 2011, compared with December 2010.

• The premiums paid to debtholders for the repurchase of the tendered principal of multiple series of senior secured notes totaled $76 million.

• A $29 million increase in energy efficiency expenditures for customer programs that are recovered through customer billings over time.

• A $17 million increase in payments to contractors for additional reliability, maintenance, and IEIMA projects.

• A $9 million increase in labor costs, primarily because of staff additions due to the requirements of the IEIMA.

• A one-time $7.5 million payment to the Illinois Science and Energy Innovation Trust as required by the IEIMA.

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

• A net $6 million reduction in previously posted collateral returned from counterparties due, in part, to changes in the market price of natural gas and in contracted volumes.

• A $6 million decrease in natural gas commodity over-recovered costs under the PGA.

Genco

Genco’s cash from operating activities decreased in the first nine months of 2012 compared with the first nine months of 2011. The following items contributed to the decrease in cash from operating activities during the first nine months of 2012, compared with the same period in 2011:

• Electric margins, as discussed in Results of Operations, decreased by $105 million, excluding impacts of noncash MTM transactions.

• An $8 million increase in payments to Ameren Illinois caused by an acceleration of the deferred intercompany tax gain caused by the closure of the Meredosia and Hutsonville energy centers.

• The coal inventory reduction in 2012 was less than the inventory reduction in 2011, which resulted in a $5 million increase in coal payments. This increase in coal payments was offset by the receipt of $3 million in 2012 for net coal transfers to refiners under agreements that did not exist during the first nine months of 2011. The coal will be purchased back from refiners in a subsequent period.

• A $2.5 million payment to AERG for the put option agreement signed on March 28, 2012. See Note 8 - Related Party Transactions under Part I, Item 1, of this report for additional information.

The following items partially offset the decrease in Genco’s cash from operating activities during the first nine months of 2012, compared with the same period in 2011:

• An $18 million reduction in accounts receivable from Marketing Company caused, in part, by lower market prices for power and reduced generation levels.

• A $6 million increase in income tax refunds, primarily due to a reduction in pretax book income partially offset by a reduction in depreciation for tax purposes.

• A $2 million decrease in pension plan contributions.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities increased in the first nine months of 2012, compared with the same period in 2011. Capital expenditures increased $147 million primarily because of increased expenditures for maintenance and reliability, boiler, turbine, and scrubber projects, which more than offset a decrease in storm restoration costs. Cash flows used in investing activities also increased due to an $11 million increase in nuclear fuel expenditures due to timing of purchases and a $48 million increase in purchases of securities, net of sales of securities, in the nuclear decommissioning trust fund. In 2012, cash flows from investing activities benefited from property sale proceeds, principally attributable to $16 million in proceeds received from the sale of Medina Valley energy center’s net property and plant. In 2011, cash flows from investing activities benefited from property sale proceeds, principally attributable to

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$45 million of proceeds received from the sale of Genco’s interest in its Columbia CT facility, 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.

Ameren Missouri’s cash used in investing activities increased during the first nine months of 2012, compared with the same period in 2011. Capital expenditures increased $43 million primarily because of increased expenditures for maintenance and reliability, boiler, and turbine projects, which more than offset a $28 million decrease in storm restoration costs. Cash flows used in investing activities also increased due to an $11 million increase in nuclear fuel expenditures due to timing of purchases and a $48 million increase in purchases of securities, net of sales of securities, in the nuclear decommissioning trust fund. In 2011, cash flows used in investing activities benefited from a $9 million payment received from the DOE in 2011 under the terms of the settlement with the DOE related to nuclear waste disposal.

Ameren Illinois’ cash used in investing activities increased during the first nine months of 2012, compared with the same period in 2011. Capital expenditures increased $48 million as a result of increased expenditures for maintenance and reliability capital projects, which more than offset a $16 million decrease in storm restoration costs. In 2011, cash flows from investing activities benefited from repayments of advances previously paid to ATXI as a result of the completion of a project under a joint ownership agreement.

Genco’s cash used in investing activities decreased during the first nine months of 2012, compared with the same period in 2011, principally attributable to a change in net money pool advances offset by an increase in capital expenditures and a reduction in proceeds related to sales of properties. During the first nine months of 2012, Genco’s capital expenditures exceeded net cash provided by operating activities by $29 million. The cash shortfall was funded by repayments of advances previously paid to the non-state-regulated subsidiaries’ money pool. In 2011, net cash provided by operating activities exceeded capital expenditures by $67 million, which allowed Genco to contribute $38 million to the non-state-regulated subsidiaries’ money pool. In 2012, capital expenditures increased by $28 million primarily because of increased expenditures related to the scrubber project at Newton energy center, which more than offset a reduction in maintenance and upgrade project expenditures due to the timing of energy center outages. In 2012, cash flows from investing activities benefited from the sales of assets for proceeds of $4 million, which resulted in a $1 million pretax loss. In 2011, cash flows from investing activities benefited from property sale proceeds, principally attributable to $45 million received from the sale of Genco’s interest in its Columbia CT facility.

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

We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other things. 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 decreased during the nine months ended September 30, 2012, compared with the same period in 2011. In 2012, Ameren subsidiaries issued $885 million in senior debt and used the proceeds, together with other available cash, to repurchase, redeem, and repay existing long-term indebtedness maturities of $754 million and pay related premiums. In 2011, Ameren Illinois funded the $150 million maturity of its senior secured notes utilizing cash on hand and operating cash flows. Additionally, repayments of net short-term debt and credit facility borrowings decreased by $236 million as a result of efforts in 2011 to reduce borrowings from short-term debt and credit facilities. There was also a reduction in refunds of advances previously received from generators of $73 million due to project completion in the first nine months of 2011. In 2011, common stock issued for DRPlus and the 401(k) plan increased cash flows from financing activities by $49 million. In 2012, Ameren shares were purchased in the open market for DRPlus and the 401(k) plan, resulting in noncash financing activity of $7 million due to the timing of DRPlus common stock dividend funding.

Ameren Missouri’s net cash used in financing activities increased during the nine months ended September 30, 2012, compared with the same period in 2011. In September 2012, Ameren Missouri issued $485 million of 3.90% senior secured notes and used the proceeds, together with other available cash, to repurchase and repay existing long-term indebtedness of $422 million and pay related premiums. Additionally, Ameren Missouri had a $81 million increase in common stock dividends. In 2011, refunds of advances previously received from generators decreased cash flows from financing activities by $19 million as a result of project completion.

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Ameren Illinois’ net cash used in financing activities decreased during the nine months ended September 30, 2012, compared with the same period in 2011. In August 2012, Ameren Illinois issued $400 million of 2.70% senior secured notes and used the proceeds, together with other available cash, to repurchase and redeem existing long-term indebtedness of $332 million and pay related premiums. In 2011, Ameren Illinois funded the $150 million maturity of its senior secured notes utilizing cash on hand and operating cash flows. In 2012, common stock dividends decreased $106 million. Additionally, there was a reduction in refunds of advances previously received from generators of $53 million due to project completion in the first nine months of 2011.

Genco’s net cash used in financing activities decreased during the nine months ended September 30, 2012, compared with the same period in 2011. In 2012, Genco was able to meet its working capital and investing requirements without utilizing financing. In 2011, Genco received a $24 million capital contribution from its parent, Resources Company, associated with a tax sharing agreement that benefited cash flows from financing activities and utilized surplus net cash from operating activities to repay $100 million of borrowing obligations.

Credit Facility Borrowings and Liquidity

The liquidity needs of Ameren, Ameren Missouri and Ameren Illinois 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 - Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information on 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 2010 Credit Agreements of Ameren (Parent), Ameren Missouri, Ameren Illinois and Genco and the credit capacity available under such agreements, considering reductions for commercial paper borrowings and letters of credit, as of September 30, 2012:

	Expiration		Borrowing Capacity			Credit Available
Ameren (Parent) and Ameren Missouri:
2010 Missouri Credit Agreement(a)		September 2013	$	800		$	800
Ameren (Parent) and Genco:
2010 Genco Credit Agreement		September 2013		500			500
Ameren (Parent) and Ameren Illinois:
2010 Illinois Credit Agreement(a)		September 2013		800			800
Ameren:
Less:
Commercial paper outstanding				(b	)		(5	)
Letters of credit				(b	)		(15	)
Total			$	2,100		$	2,080

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

^(b) Not applicable.

The 2010 Credit Agreements are used to make 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. 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.

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The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In April 2012, FERC issued an order authorizing the issuance of up to $1 billion of short-term debt securities for Ameren Missouri. The authorization was effective immediately and terminates on March 31, 2014. 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 terminated on September 30, 2012. In July 2012, Ameren Illinois requested authorization to issue up to $1 billion of short-term debt securities due to the previous authorization that was terminated in September. On September 20, 2012, FERC issued an order authorizing the issuance. The authorization was effective as of October 1, 2012 and terminates on September 30, 2014.

Genco has unlimited long and short-term debt issuance authorization from FERC. EEI has unlimited short-term debt issuance 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 issuances, redemptions, repurchases and maturities of long-term debt (net of any issuance discounts) for the nine months ended September 30, 2012, and 2011, for the Ameren Companies. For additional information, see Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report.

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	Month Issued, Redeemed, Repurchased or Matured	Nine Months
		2012		2011
Issuances
Long-term debt
Ameren Missouri:
3.90% Senior secured notes due 2042	September	$	482	$	-
Ameren Illinois:
2.70% Senior secured notes due 2022	August		400		-
Total Ameren long-term debt issuances		$	882	$	-
Common stock
Ameren:
DRPlus and 401(k)	Various	$	-	$	49
Total common stock issuances		$	-	$	49
Total Ameren long-term debt and common stock issuances		$	882	$	49
Redemptions, Repurchases and Maturities
Long-term debt
Ameren Missouri:
5.25% Senior secured notes due 2012	September	$	173	$	-
6.00% Senior secured notes due 2018	September		71		-
6.70% Senior secured notes due 2019	September		121		-
5.10% Senior secured notes due 2018	September		1		-
5.10% Senior secured notes due 2019	September		56		-
Ameren Illinois:
6.625% Senior secured notes due 2011	June		-		150
9.75% Senior secured notes due 2018	August		87		-
6.25% Senior secured notes due 2018	August		194		-
2000 Series A 5.50% pollution control revenue bonds due 2014	August		51		-
Total Ameren long-term debt redemptions, repurchases and maturities		$	754	$	150

In June 2012, Ameren, Ameren Missouri and Ameren Illinois filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in June 2015.

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 - Short-term Debt and Liquidity and Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report and Note 4 - Short-Term Debt 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 (and applicable cross-default provisions) contained in our bank credit and term loan agreements and in certain of the Ameren Companies’ indentures and articles of incorporation.

At September 30, 2012, the Ameren Companies were in compliance with the provisions and covenants contained within their credit agreements, 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 its current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri and Ameren Illinois each believes that it will continue to have access to the capital markets. However, events beyond Ameren’s, Ameren Missouri’s and Ameren Illinois’ 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.

Genco’s operating results and operating cash flows are significantly affected by changes in market prices for power, which have significantly decreased over the past few years. Under the provisions of Genco’s indenture described in Note 4 - Long-term Debt and Equity Financings, in Part I, Item 1, of this report, Genco may not borrow additional funds from external, third-party sources if its interest coverage ratio is less than a specified minimum or its leverage ratio is greater than a specified maximum. Based on projections as of September 30, 2012, of its operating results and cash flows, Genco expects that, by the end of the first quarter of 2013, its interest coverage ratio will be less than the minimum ratio required for the company to borrow additional funds from external, third-party sources. Genco’s indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren’s control, and if a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time.

In March 2012, Genco entered into a put option agreement with AERG, that gives Genco an irrevocable option to sell to AERG the Grand Tower, the Gibson City, and the Elgin energy centers, in order to provide an additional source of liquidity, if needed, in the future. See Note 8 - Related Party Transactions, in Part I, Item 1, of this report for additional information regarding the put option agreement and Ameren’s guaranty of AERG’s contingent obligations under the put option agreement.

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Dividends

Ameren declared common stock dividends totaling $291 million, or $1.20 per share, and paid $284 million to its stockholders during the first nine months of 2012 (2011 - $279 million or $1.155 per share). On October 12, 2012, Ameren’s board of directors declared a quarterly common stock dividend of 40 cents per share payable on December 31, 2012, to stockholders of record on December 12, 2012.

Genco’s indenture includes restrictions that can prohibit it from making dividend payments on its common stock. Specifically, Genco cannot pay dividends on its common stock unless the company’s actual interest coverage ratio for the most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on projections as of September 30, 2012, of Genco’s operating results and cash flows, we do not expect that Genco will achieve the minimum interest coverage ratio necessary to pay dividends on its common stock for the six months ended March 31, 2013, or the six months ended September 30, 2013. As a result, Genco was restricted from paying dividends on its common stock as of September 30, 2012, and we expect Genco will be unable to pay dividends on its common stock through at least September 30, 2015.

See Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report and Note 4 - Short-term Debt and Liquidity and Note 5 - Long-term Debt and Equity Financings under Part II, Item 8, of the Form 10-K for additional 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, 2012, none of these circumstances existed at Ameren, Ameren Missouri and Ameren Illinois and, as a result, these companies were not restricted from paying 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 Corporation, for the nine months ended September 30, 2012, and 2011:

	Nine Months
	2012		2011
Ameren Missouri	$	300	$	219
Ameren Illinois		132		238
Dividends paid by Ameren		284		279

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, 2012, total other obligations related to the procurement of coal, natural gas, nuclear fuel, purchased power, methane gas, equipment and meter reading services, and a tax credit obligation, among other agreements, at Ameren, Ameren Missouri, Ameren Illinois and Genco were $8,962 million, $5,630 million, $2,508 million, and $522 million, respectively. Total unrecognized tax benefits at September 30, 2012, which were not included in the totals above, for Ameren, Ameren Missouri, Ameren Illinois and Genco were $167 million, $143 million, $11 million, and $12 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	Baa2	BBB-	BBB-
Secured debt	A3	BBB/BBB+(a)	BBB+
Senior unsecured debt	Baa2	BBB-	BBB
Genco:
Issuer/corporate credit rating	-	BB-	BB-
Senior unsecured debt	Ba3	BB-	BB-

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

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

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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, 2012, were $121 million, $15 million, $76 million, and $- million at Ameren, Ameren Missouri, Ameren Illinois, and Genco, respectively. Cash collateral posted by external counterparties with Ameren and Ameren Illinois was $4 million and $2 million, respectively, at September 30, 2012. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at September 30, 2012, 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 $244 million, $80 million, $72 million, and $38 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, 2012, 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 $196 million, $14 million, $- million, and $29 million, respectively. If market prices were 15% lower than September 30, 2012, 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 $137 million, $5 million, $21 million, and $43 million, respectively.

OUTLOOK

Ameren seeks to earn competitive returns on its investments in its businesses. Ameren Missouri and Ameren Illinois are seeking to improve their regulatory frameworks and cost recovery mechanisms. At the same time, Ameren’s rate-regulated businesses are pursuing constructive regulatory outcomes within existing frameworks and are seeking to align their overall spending, both operating and capital, with economic conditions 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 coal-fired and natural gas generating assets. Ameren’s merchant generation strategy is to position itself as a low-cost provider and to benefit from an expected future 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, events, and uncertainties that are reasonably likely to affect the Ameren Companies’ results of operations, financial condition, or liquidity, as well as their ability to achieve strategic and financial objectives, for 2012 and beyond.

Rate-Regulated Operations

• Ameren’s strategy for earning competitive returns on its rate-regulated investments involves meeting customer energy needs in an efficient fashion, working to enhance regulatory frameworks, making timely and well-supported rate case filings, and aligning overall spending with those rate case outcomes, economic conditions and return opportunities.

• In September 2012, the ICC issued an order on Ameren Illinois’ initial IEIMA filing that approved a $55 million decrease in Ameren Illinois’ annual electric delivery service revenue requirement from the electric delivery service revenue requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The new rates became effective on October 19, 2012. Ameren Illinois requested a rehearing of the initial filing order, which the ICC denied. In October 2012, Ameren Illinois filed an appeal of the ICC order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013. Ameren Illinois filed an update filing based on 2011 costs and expected net plant additions for 2012, which would result in a $17 million increase in annual electric delivery service revenues from the amount allowed in the ICC initial rate order. Pending ICC approval, rates from the update filing are expected to become effective on January 1, 2013. In the update filing proceeding, the ICC staff and the administrative law judges are recommending a reduction to Ameren Illinois’ annual electric delivery service revenues. We believe that our participation in this framework will better enable Ameren Illinois to earn its allowed return on equity for its electric delivery service business. This framework is expected to give Ameren Illinois the earnings predictability to invest in modernizing its distribution system.

• The IEIMA provides for an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for that year. Consequently, Ameren Illinois’ 2012 electric delivery service revenues will be based on its 2012 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA’s performance-based formula ratemaking framework. The 2012 revenue

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requirement under the IEIMA’s formula ratemaking framework is expected to be lower than the revenue requirement included in both the ICC’s 2010 electric rate order and the ICC’s September 2012 order related to Ameren Illinois’ initial IEIMA filing. As a result, Ameren Illinois recorded a regulatory liability to represent its estimate of the probable decrease in electric delivery service rates expected to be approved by the ICC to provide Ameren Illinois recovery of all prudently and reasonably incurred costs and an earned rate of return on common equity for 2012. Ameren Illinois’ actual return on equity relating to electric delivery service cannot exceed 50 basis points above or below its allowed return. During the third quarter of 2012, Ameren Illinois’ electric delivery service return on equity was capped at the maximum allowed return on equity included in the IEIMA formula rate framework. As of September 30, 2012, Ameren Illinois recorded a cumulative regulatory liability of $35 million with a corresponding decrease in electric revenues for electric delivery service relating to the 2012 revenue requirement reconciliation and the collar adjustment on earnings, which will be refunded to customers during 2014 with interest pursuant to the provisions of the IEIMA.

• In February 2012, Ameren Missouri filed a request with the MoPSC to increase its annual revenue for electric service. The currently pending request, as amended in October 2012, seeks an annual revenue increase of $323 million. This request includes recovery of the cost of the proposed energy efficiency programs included in the MEEIA filing. The MoPSC staff is currently recommending an increase to Ameren Missouri’s annual revenues of $210 million. A decision by the MoPSC in this proceeding is expected in December 2012, with rates becoming effective on January 2, 2013.

• As they continue to experience cost recovery pressures, Ameren Missouri and Ameren Illinois expect to regularly seek electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. These pressures include lower load growth from a weak economy, customer conservation efforts and the impacts of energy efficiency programs, increased investments and expected future investments for environmental compliance, system reliability improvements, and new baseload capacity, including renewable requirements. Increased investments also result in higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs, higher property and income taxes, and higher insurance premiums as a result of insurance market conditions and industry loss experience, among other things.

• Following recommendations from the NRC’s task force on lessons learned from the 2011 reactor accident in Japan, the NRC issued orders in March 2012 requiring United States nuclear plants to enhance nuclear plant readiness to safely manage severe events. These orders concentrated on addressing seismic and flooding risks, emergency planning, spent fuel risks, and severe accidents. Ameren Missouri is conducting an analysis to determine how to comply with the orders. The NRC provided a four-year compliance period. Such orders are expected to result, and potential future orders may result, in increased costs and capital investments.

• In January 2012, the ICC issued an order that authorized a $32 million increase in Ameren Illinois’ annual natural gas delivery service revenues. This order was based on a future test year of 2012, rather than a historical test year, in order to improve the ability to earn returns allowed by regulators.

• The MoPSC issued an order, in April 2011, with respect to its review of Ameren Missouri’s FAC for the period from March 1, 2009, to September 30, 2009. The order required Ameren Missouri to refund $18 million, including $1 million for interest, to customers related to pretax earnings associated with certain long-term partial requirements sales that were made by Ameren Missouri due to the loss of Noranda’s load caused by a severe ice storm in January 2009. Ameren Missouri appealed this decision to the Cole County Circuit Court, which overturned the MoPSC’s April 2011 order. The Cole County Circuit Court decision is being appealed by the MoPSC to the Missouri Court of Appeals. It is possible that the MoPSC could order additional refunds of approximately $25 million related to pretax earnings associated with these long-term partial requirements sales in periods after September 2009, and this could result in a charge to earnings in the period in which such an order is received. Separately, Ameren Missouri filed a request with the MoPSC in July 2011 for an accounting authority order that would allow Ameren Missouri to recover fixed costs totaling $36 million that were not recovered as a result of the loss of load caused by the severe 2009 ice storm for potential recovery in a future electric rate case. If the courts ultimately rule in favor of Ameren Missouri’s position regarding the classification of the long-term partial requirements sales, Ameren Missouri would not seek to recover from customers the sum that would be covered by the accounting authority order if it is granted.

• In August 2012, the MoPSC issued an order that approved a stipulation and agreement regarding Ameren Missouri’s MEEIA filing. The order includes megawatthour savings targets for its energy efficiency programs as well as associated cost recovery mechanisms and incentive awards. Beginning in 2013, Ameren Missouri expects to invest approximately $147 million over three years for energy efficiency programs. The order also allows for Ameren Missouri to collect, over the next three years, its program costs and 90% of

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its projected lost revenue from customers starting on January 2, 2013. The remaining 10% of projected lost revenue is expected to be recovered as part of future rate proceedings. Additionally, the order provides for an incentive award based on the achievement of certain energy efficiency goals, including approximately $19 million if 100% of Ameren Missouri’s energy efficiency goals are achieved during the three-year period, with the potential to earn more if energy savings exceeds those goals. The recovery of the incentive award from customers, if the energy efficiency goals are achieved, would begin after the three-year energy efficiency plan is complete and upon the effective date of an electric service rate case or potentially with the future adoption of a rider mechanism.

• Ameren and Ameren Missouri also are pursuing recovery from insurers, through litigation, for reimbursement of unpaid liability insurance claims for a December 2005 breach of the upper reservoir at Ameren Missouri’s Taum Sauk pumped-storage hydroelectric energy center.

• Approximately 340 employees of Ameren Missouri and Ameren Services accepted voluntary separation offers and left the company as of December 31, 2011. As a result of the voluntary separations, Ameren and Ameren Missouri estimate an annual $20 million reduction in labor-related operations and maintenance expense in 2012.

• Ameren Missouri’s Callaway energy center completed a scheduled refueling and maintenance outage during the fourth quarter of 2011. The next scheduled refueling and maintenance outage is in the spring of 2013. 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, versus non-outage years.

• Ameren Missouri continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. Environmental regulations, as well as future initiatives related to greenhouse gas emissions and global climate change, could result in significant increases in capital expenditures and operating costs. The compliance costs could be prohibitive at some of Ameren Missouri’s coal-fired energy centers, particularly at its Meramec energy center, as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures for their continued operation.

• Ameren intends to allocate its capital to those investment opportunities with the highest expected risk-adjusted returns. Ameren believes that because of its strategic location in the country, electric transmission may provide it with such an opportunity. In December 2011, MISO approved three projects, which will be developed by ATXI. The first project, Illinois Rivers, involves building a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. Design and planning work on the first sections of this project have begun with construction scheduled to begin in 2013 after receiving a certificate of public convenience and necessity from the ICC, which ATXI requested in November 2012. The first sections of the Illinois Rivers project are expected to be in-service in 2016. The last section of this project is expected to be completed in 2019. The Spoon River project in northwest Illinois and the Mark Twain project in northeast Missouri are the other two projects approved by MISO in its current transmission expansion plan. These two projects are expected to be completed in 2018. The estimated total investment in these three projects is expected to be more than $1.3 billion. FERC, in its order issued in May 2011, approved transmission rate incentives for the Illinois Rivers project as well as for the Big Muddy River project. The Big Muddy River project, located primarily in southern Illinois, is being evaluated for inclusion in MISO’s transmission expansion plans. In July 2012, Ameren, on behalf of its transmission affiliates, filed a request with FERC seeking transmission rate incentives for the Spoon River project and the Mark Twain project. Ameren expects FERC will issue an order in 2012.

• For additional information regarding recent rate orders and related appeals, pending requests filed with state and federal regulatory commissions, the FAC prudence review and related appeal, Taum Sauk matters, and separate FERC orders impacting Ameren Missouri and Ameren Illinois, see 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 and Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K.

Merchant Generation Operations

• In this period of historically weak power prices and margins, Ameren is focused on improving and reducing the volatility of operating cash flows within its Merchant Generation business so that cash flows from operations approximate nonoperating cash requirements. The Merchant Generation business has reduced operating costs and sought cost-efficient methods to comply with significant environmental requirements, and expects to continue to pursue these strategies while positioning itself for an expected future recovery in power prices and margins.

• The Merchant Generation segment expects to have available generation from its coal-fired energy centers of 32.5 million megawatthours in any given year (Genco - 24.5 million). However, based on currently expected power prices, the Merchant Generation segment expects to generate approximately 26 million (Genco - 19 million) megawatthours, which includes generation from non-coal-fired energy centers, in 2012.

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• Power prices in the Midwest affect the amount of revenues and cash flows the Merchant Generation business and Genco can realize by marketing power into the wholesale and retail markets. Ameren’s Merchant Generation segment and Genco are adversely impacted by the declining market price of power for any unhedged generation. Market prices for power have decreased over the past four years. During the first quarter of 2012, the observable market price of power for delivery in the current year and in future years in the Midwest sharply declined below 2011 levels primarily because of declining natural gas prices and the impact of the stay of the CSAPR. At that time, Merchant Generation and Genco evaluated this sharp price decline, and the related impact on electric margins, as well as the impact of the stay of the CSAPR, and the potential impact these events may have on their operating and capital investment plans. In February 2012, Genco decelerated the construction of two scrubbers at its Newton energy center. In September 2012, the Illinois Pollution Control Board granted AER a variance to extend compliance dates for SO₂ emission levels contained in the MPS through December 31, 2019, subject to certain conditions. The Illinois Pollution Control Board approved AER’s proposed plan to restrict its SO₂ emissions through 2014 to levels lower than those required by the existing MPS to offset any environmental impact from the variance. The order also established a schedule of milestones for completion of various aspects of the installation and completion of the scrubber project at Genco’s Newton energy center; the first milestone relates to the completion of engineering design by July 2015 while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019.

• The sharp decline in the market price of power in the first quarter of 2012 and the related impact on electric margins, as well as the deceleration of construction of Genco’s Newton energy center scrubber project, caused Merchant Generation and Genco to evaluate whether the carrying values of their energy centers were recoverable. As a result of this evaluation, Ameren recorded an asset impairment charge to reduce the carrying value of AERG’s Duck Creek energy center to its estimated fair value in the first quarter of 2012. See Note 11 - Asset Impairments in Part I, Item 1, of this report for additional information. As a result of Duck Creek’s reduced net property and plant carrying value, Ameren estimates that annual depreciation expense will be reduced by $25 million.

• After the impairment of the Duck Creek energy center in the first quarter of 2012, Merchant Generation and Genco believed the carrying value of their energy centers exceeded their estimated fair values by an amount significantly in excess of $1 billion. However, under the applicable accounting guidance, an asset is not deemed impaired, and no impairment loss is recognized, unless the asset’s carrying value exceeds the estimated undiscounted future cash flows, even if the carrying value of the asset exceeds estimated fair value. Merchant Generation and Genco could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted cash flows no longer exceed carrying values for long-lived assets as a result of factors outside their control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of Merchant Generation’s and Genco’s energy centers, and also as a result of factors that may be within their control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell their energy centers.

• To reduce cash flow volatility, Marketing Company, through a mix of physical and financial sales contracts, 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, 2012, Marketing Company had hedged approximately 28 million megawatthours of Merchant Generation’s expected generation for 2012, at an average price of $43 per megawatthour. The approximately 2 million megawatthours of hedging in excess of expected 2012 generation is expected to be settled on a profitable basis using financial instruments. For 2013, Marketing Company had hedged approximately 24 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $36 per megawatthour. For 2014, Marketing Company had hedged approximately 13 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $38 per megawatthour. 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.

• In June 2012, FERC approved MISO’s proposal to establish an annual capacity market within the RTO. MISO’s inaugural annual capacity auction will be held in March 2013 for the June 2013 to May 2014 planning year. Participation in MISO’s capacity auction is voluntary for load servicing entities as they will continue to be able to plan to meet all of their resource

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requirements outside of the auction, including through self-supply and/or bilateral contracts. Ameren, Ameren Missouri, Ameren Illinois and Genco are reviewing FERC’s order to determine its impact on their results of operations, financial position, and liquidity.

• To further reduce cash flow volatility, Merchant Generation seeks to hedge fuel costs consistent with power sales. As of September 30, 2012, 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 22 million megawatthours of coal and up to 27 million megawatthours of base transportation at about $23.50 per megawatthour. For 2014, Merchant Generation had hedged fuel costs for approximately 13 million megawatthours of coal and up to 21 million megawatthours of base transportation at about $24 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 2012 through 2016.

• In June 2012, EEI announced that it was reducing its workforce by 44 employees, which included both management and labor union represented employees, in response to lower demand and prices for electricity. By the end of September 2012, the staff reduction was materially complete. Going forward, the workforce reduction is expected to reduce EEI’s annual pretax other operations and maintenance expenses by $2 million to $3.5 million. Additionally, during September 2012, EEI’s management and labor union postretirement medical benefit plans were amended to adjust for moving to a Medicare Advantage plan, which resulted in a remeasurement and reduction of the benefit obligation. Genco estimates the pretax impact of the lower benefit obligation will result in a $5 million to $10 million reduction in postretirement benefits expense during 2013.

Liquidity and Capital Resources

• The Ameren Companies seek to maintain access to the capital markets at commercially attractive rates in order to fund their businesses. The enhancement of regulatory frameworks and returns is expected to improve cash flows, credit metrics, and related access to capital for Ameren’s rate-regulated businesses.

• Genco and the Merchant Generation segment seek to fund their operations internally and therefore seek not to rely on financing from Ameren or external, third-party sources. Genco and the Merchant Generation segment will continue to seek to defer or reduce capital and operating expenses, sell certain assets, and take other actions as necessary to fund their operations internally while maintaining safe and reliable operations. Consistent with these objectives, in March 2012, Genco entered into a put option agreement with AERG for the potential sale of the Grand Tower, the Gibson City, and the Elgin energy centers, in order to provide an additional source of liquidity, if needed in the future.

• Under its indenture, Genco may not borrow additional funds from external, third-party sources if its interest coverage ratio is less than a specified minimum or its leverage ratio is greater than a specified maximum. Based on projections as of September 30, 2012, of Genco’s operating results and cash flows, we expect that, by the end of the first quarter of 2013, Genco’s interest coverage ratio will be less than the minimum ratio required for the company to borrow additional funds from external, third-party sources. Genco’s indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren’s control, and if a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time. Additionally, Genco cannot pay dividends on its common stock unless the company’s actual interest coverage ratio for the most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on projections as of September 30, 2012, of Genco’s operating results and cash flows, we do not expect that Genco will achieve the minimum interest coverage ratio necessary to pay dividends on its common stock for the six months ended March 31, 2013, or the six months ended September 30, 2013. As a result, Genco was restricted from paying dividends on its common stock as of September 30, 2012, and we expect Genco will be unable to pay dividends on its common stock through at least September 30, 2015.

• The Ameren Companies have also entered into multiyear credit facility agreements that cumulatively provide $2.1 billion of credit through September 10, 2013. Ameren, Ameren Missouri and Ameren Illinois expect to replace during the fourth quarter of 2012 their existing credit facility agreements with new five-year credit facility agreements that would cumulatively provide $2.1 billion of credit. The 2010 Genco Credit Agreement is not expected to be renewed and is expected to be terminated during the fourth quarter of 2012. Ameren, Ameren Missouri and Ameren Illinois believe that their liquidity is adequate given their 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 their ability to execute their expected operating, capital or financing plans.

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• As of September 30, 2012, Ameren had approximately $590 million in federal income tax net operating loss carryforwards (Ameren Missouri - $175 million, Ameren Illinois - $165 million, Genco - $70 million) and $86 million in federal income tax credit carryforwards (Ameren Missouri - $13 million, Ameren Illinois - $- million, Genco - $1 million). These carryforwards are expected to offset income tax liabilities for Ameren Missouri into 2013, and into 2014 for Ameren Illinois and Genco consistent with the tax sharing agreement.

• Between 2012 and 2021, Ameren currently expects to invest between $1.7 billion to $2.0 billion to retrofit its coal-fired energy centers with pollution control equipment in compliance with environmental laws and regulations. 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 energy centers.

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 or index. 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.

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, 2012.

Our rate-regulated 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, 2012, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. Additionally, Ameren Illinois has risk associated with the purchase of receivables. The Illinois Public Utilities Act requires Ameren Illinois to establish electric utility consolidated billing and purchase of receivables services. At the option of an alternative retail electric supplier, Ameren Illinois is required to purchase the supplier’s receivables relating to Ameren Illinois’ delivery service customers who elected to receive power supply from the alternative retail

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electric supplier. If that option is selected, Ameren Illinois produces consolidated bills for the applicable retail customers reflecting charges for electric delivery service and purchased receivables. Beginning in June 2012, Ameren Illinois began purchasing trade receivables relating to the power supply of residential customers using Marketing Company as their alternative retail electric supplier. As of September 30, 2012, Ameren Illinois’ balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $13 million. 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, 2012, Ameren’s, Ameren Missouri’s, Ameren Illinois’ and Genco’s combined credit exposure to nonaffiliated trading counterparties, excluding coal suppliers, deemed below investment grade either through external or internal credit evaluations, was less than $1 million, net of collateral (2011 - $57 million). At September 30, 2012, the combined credit exposures to nonaffiliated coal suppliers deemed below investment grade either through external or internal credit evaluations, net of collateral, was $16 million at Ameren, $3 million at Ameren Missouri and $8 million at Genco. (2011- $204 million, $174 million, $21 million, respectively).

We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program. Monitoring 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 $7 million at September 30, 2012 (2011 - $40 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, transportation 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 remaining quarter of 2012 through 2016:

	Net Income(a)
Ameren(b)	$	(12	)
Ameren Missouri		(c	)
Genco		(11	)

(a) Calculations are based on an effective tax rate of 39%, 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, 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. Additionally, the type of coal burned is part of Ameren Missouri’s environmental compliance strategy. Ameren Missouri has a multiyear agreement to purchase ultra-low-sulfur coal through 2017 to comply with environmental regulations.

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.

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In addition, coal and coal transportation costs are sensitive to the price of diesel fuel as a result of rail freight fuel surcharges. We use forward fuel oil contracts (both for heating and crude oil) to mitigate this market price risk as changes in these products are highly correlated to changes in diesel markets. If diesel fuel costs were to increase or decrease by $0.25 a gallon, Ameren’s fuel expense could increase or decrease by $14 million annually (Ameren Missouri - $8 million, Genco - $5 million). As of September 30, 2012, Ameren had a price cap for 99% of expected fuel surcharges in 2012.

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’s 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 for approximately 79% of its 2013 to 2016 nuclear fuel requirements.

The electric generating operations for Ameren, Ameren Missouri and Genco are exposed to changes in market prices for natural gas used to run CTs. Their 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.

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 costs for fuel, purchased power, and gas supply. 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, 2012, 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 five-year period 2012 through 2016. 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.

	2012			2013			2014 - 2016
Ameren(a):
Coal		100	%		91	%		68	%
Coal transportation		100			99			89
Nuclear fuel		100			94			71
Natural gas for generation		100			33			1
Natural gas for distribution(b)		74			27			10
Purchased power for Ameren Illinois(c)		100			100			42
Ameren Missouri:
Coal		100	%		98	%		96	%
Coal transportation		100			98			98
Nuclear fuel		100			94			71
Natural gas for generation		100			4			1
Natural gas for distribution(b)		79			29			17
Ameren Illinois:
Natural gas for distribution(b)		74	%		27	%		9	%
Purchased power(c)		100			100			42
Genco:
Coal		100	%		78	%		30	%
Coal transportation		100			100			71
Natural gas for generation		100			47			-

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

(b) Represents the percentage of natural gas price hedged for peak winter season of November through March. The year 2012 represents November 2012 through March 2013. The year 2013 represents November 2013 through March 2014. This continues each successive year through March 2017.

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

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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 2012 through 2016.

	Coal						Coal Transportation
	Fuel Expense			Net Income(a)			Fuel Expense			Net Income(a)
Ameren(b)(c)	$	5		$	(3	)	$	2		$	(1	)
Ameren Missouri(c)		(d	)		(d	)		(d	)		(d	)
Genco		4			(2	)		2			(1	)

(a) Calculations are based on an effective tax rate of 39%, 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

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, 2012. We use various methods to determine the fair value of our contracts. In accordance with authoritative guidance for fair value hierarchy levels, the sources we 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). 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, 2012	Ameren(a)			Ameren Missouri			Ameren Illinois			Genco			Other(b)
Fair value of contracts at beginning of period, net	$	(177	)	$	10		$	(363	)	$	(4	)	$	180
Contracts realized or otherwise settled during the period		23			(1	)		75			(3	)		(48	)
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-
Fair value of new contracts entered into during the period		7			1			-			4			2
Other changes in fair value		16			3			21			3			(11	)
Fair value of contracts outstanding at end of period, net	$	(131	)	$	13		$	(267	)	$	-		$	123
Nine Months Ended September 30, 2012
Fair value of contracts at beginning of year, net	$	(43	)	$	18		$	(307	)	$	10		$	236
Contracts realized or otherwise settled during the period		41			(22	)		240			(7	)		(170	)
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-
Fair value of new contracts entered into during the period		27			19			1			(4	)		11
Other changes in fair value		(156	)		(2	)		(201	)		1			46
Fair value of contracts outstanding at end of period, net	$	(131	)	$	13		$	(267	)	$	-		$	123

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

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

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The following table presents maturities of derivative contracts as of September 30, 2012, 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	$	6		$	(8	)	$	-		$	-		$	(2	)
Level 2(a)		(58	)		(44	)		(3	)		-			(105	)
Level 3(b)		31			11			(16	)		(50	)		(24	)
Total	$	(21	)	$	(41	)	$	(19	)	$	(50	)	$	(131	)
Ameren Missouri:
Level 1	$	4		$	(4	)	$	-		$	-		$	-
Level 2(a)		(2	)		(3	)		-			-			(5	)
Level 3(b)		15			3			-			-			18
Total	$	17		$	(4	)	$	-		$	-		$	13
Ameren Illinois:
Level 1	$	-		$	-		$	-		$	-		$	-
Level 2(a)		(58	)		(42	)		(2	)		-			(102	)
Level 3(b)		(78	)		(20	)		(17	)		(50	)		(165	)
Total	$	(136	)	$	(62	)	$	(19	)	$	(50	)	$	(267	)
Genco:
Level 1	$	2		$	(3	)	$	-		$	-		$	(1	)
Level 2(a)		-			-			-			-			-
Level 3(b)		-			-			1			-			1
Total	$	2		$	(3	)	$	1		$	-		$	-

(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, 2012, 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 April 2011 FAC prudence review order and completion of the current FAC prudence review;

• electric rate proceedings for Ameren Missouri pending before the MoPSC and for Ameren Illinois pending before the ICC;

• Ameren Illinois’ appeal of the ICC’s September 2012 initial IEIMA rate order;

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• FERC litigation to determine wholesale distribution revenues for five of Ameren Illinois’ wholesale customers;

• Entergy appeal of a FERC May 2012 order requiring Entergy to refund to Ameren Missouri additional charges Ameren Missouri paid under an expired power purchase agreement;

• Ameren Illinois’ request for rehearing of a July 2012 FERC order;

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

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

• Genco’s challenge before the Informal Conference Board of the Illinois Department of Revenue regarding the State’s position that EEI did not qualify for manufacturing tax exemptions for 2010 transactions.

ITEM 1A. RISK FACTORS.

The Form 10-K includes a detailed discussion of our risk factors. The information presented below updates, and should be read in conjunction with, the risk factors and information disclosed in the Form 10-K.

Ameren and Genco could recognize long-lived asset impairment charges related to the Merchant Generation segment’s and Genco’s energy centers.

After the impairment of the Duck Creek energy center in the first quarter of 2012, Ameren’s Merchant Generation segment and Genco believed the carrying value of their energy centers exceeded their estimated fair values by an amount significantly in excess of $1 billion. However, under the applicable accounting guidance, an asset is not deemed impaired, and no impairment loss is recognized, unless the asset’s carrying value exceeds the estimated undiscounted future cash flows, even if the carrying value of the asset exceeds estimated fair value. Ameren’s Merchant Generation segment and Genco will continue to monitor the market price for power and the related impact on electric margin and other events or changes in circumstances that indicate that the carrying value of their energy centers may not be recoverable as compared to their undiscounted cash flows. Ameren and Genco could recognize additional, material long-lived asset impairment charges in the future as a result of factors outside their control, such as changes in power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of Merchant Generation’s and Genco’s energy centers, and also as a result of factors that may be within their control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell their energy centers.

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

The following table presents purchases of Ameren Corporation’s 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, 2012		435	$	33.50		-		-
August 1 - August 31, 2012		289		33.28		-		-
September 1 - September 30, 2012		-		-		-		-
Total		724	$	33.41		-		-

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

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, 2012, to September 30, 2012.

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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 the Rights of Security Holders, Including Indentures
4.1	Ameren Ameren Missouri	Ameren Missouri Indenture Company Order dated September 11, 2012, establishing the 3.90% Senior Secured Notes due 2042
4.2	Ameren Ameren Missouri	Global Note, dated September 11, 2012, representing the 3.90% Senior Secured Notes due 2042	September 11, 2012 Form 8-K, Exhibit 4.2, File No. 1-2967
4.3	Ameren Ameren Missouri	Supplemental Indenture to the Ameren Missouri Mortgage dated September 1, 2012, relative to Series OO	September 11, 2012 Form 8-K, Exhibit 4.4, File No. 1-2967
4.4	Ameren Ameren Illinois	Ameren Illinois Indenture Company Order dated August 20, 2012, establishing the 2.70% Senior Secured Notes due 2022	August 20, 2012 Form 8-K, Exhibit 4.2, File No. 1-3672
4.5	Ameren Ameren Illinois	Global Note, dated August 20, 2012, representing the 2.70% Senior Secured Notes due 2022	August 20, 2012 Form 8-K, Exhibit 4.3, File No. 1-3672
4.6	Ameren Ameren Illinois	Supplemental Indenture to the Ameren Illinois Mortgage dated as of August 1, 2012, relative to Series EE	August 20, 2012 Form 8-K, Exhibit 4.4, File No. 1-3672
Material Contracts
10.1	Ameren Illinois	Separation Agreement, effective as of September 4, 2012, between Scott A. Cisel and Ameren Illinois Company
10.2	Ameren Companies	*Revised Schedule I to Second Amended and Restated Change of Control Severance Plan, as amended
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

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Exhibit Designation	Registrant (s)	Nature of Exhibit	Previously Filed as Exhibit to:
31.4	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Missouri
31.5	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois
31.6	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois
31.7	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco
31.8	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Genco
Section 1350 Certifications
32.1	Ameren	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren
32.2	Ameren Missouri	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri
32.3	Ameren Illinois	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Illinois
32.4	Genco	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco
XBRL - Related Documents
101.INS**	Ameren Companies	XBRL Instance Document
101.SCH**	Ameren Companies	XBRL Taxonomy Extension Schema Document
101.CAL**	Ameren Companies	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**	Ameren Companies	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	Ameren Companies	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF**	Ameren Companies	XBRL Taxonomy Extension Definition Document

* Compensatory plan or arrangement.

** Attached as Exhibit 101 to this report is the following financial information from Ameren’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statement of Income for the three and nine months ended September 30, 2012, and 2011, (ii) the Consolidated Statement of Comprehensive Income for the three and nine months ended September 30, 2012, and 2011, (iii) the Consolidated Balance Sheet at September 30, 2012, and December 31, 2011, (iv) the Consolidated Statement of Cash Flows for the nine months ended September 30, 2012, and 2011, and (v) the Combined Notes to the Financial Statements for the nine months ended September 30, 2012. For Ameren Missouri, Ameren Illinois, and Genco, these exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.

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

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SIGNATURES

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

AMEREN CORPORATION

(Registrant)

/s/ Martin J. Lyons, Jr.

     Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

UNION ELECTRIC COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

     Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

AMEREN ILLINOIS COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

     Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

AMEREN ENERGY GENERATING COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

     Martin J. Lyons, Jr.

Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

Date: November 9, 2012

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