10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Quarterly Period Ended March 31, 2013

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)
	6 Executive Drive
	Collinsville, Illinois 62234
	(618) 343-8039

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	ý	No	¨
Union Electric Company	Yes	ý	No	¨
Ameren Illinois Company	Yes	ý	No	¨

Indicate by check mark whether each registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 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	ý	No	¨
Union Electric Company	Yes	ý	No	¨
Ameren Illinois Company	Yes	ý	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	ý	¨	¨	¨
Union Electric Company	¨	¨	ý	¨
Ameren Illinois Company	¨	¨	ý	¨

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	ý
Union Electric Company	Yes	¨	No	ý
Ameren Illinois Company	Yes	¨	No	ý

The number of shares outstanding of each registrant’s classes of common stock as of April 30, 2013, 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

______________________________________________________________________________________________________ 

This combined Form 10-Q is separately filed by Ameren Corporation, Union Electric Company, and Ameren Illinois 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		1
Forward-looking Statements		1
PART I Financial Information
Item 1.	Financial Statements (Unaudited)	3
	Ameren Corporation	3
	Consolidated Statement of Income (Loss)	3
	Consolidated Statement of Comprehensive Income (Loss)	4
	Consolidated Balance Sheet	5
	Consolidated Statement of Cash Flows	6
	Union Electric Company	7
	Statement of Income and Comprehensive Income	7
	Balance Sheet	8
	Statement of Cash Flows	9
	Ameren Illinois Company	10
	Statement of Income and Comprehensive Income	10
	Balance Sheet	11
	Statement of Cash Flows	12
	Combined Notes to Financial Statements	13
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	55
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	73
Item 4.	Controls and Procedures	76
PART II Other Information
Item 1.	Legal Proceedings	77
Item 1A.	Risk Factors	77
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	78
Item 6.	Exhibits	78
Signatures		80

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 1 and 2 of this Form 10-Q under the heading “Forward-looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.

GLOSSARY OF TERMS AND ABBREVIATIONS

We use the words “our,” “we” or “us” with respect to certain information that relates to Ameren, Ameren Missouri, and Ameren Illinois, collectively. 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.

AER - Ameren Energy Resources Company, LLC, an Ameren Corporation subsidiary that consists of non-rate-regulated operations, including Genco, AERG, Marketing Company and Medina Valley through March 13, 2013. Medina Valley was distributed from AER to Ameren on March 14, 2013.

Dynegy - Dynegy, Inc.

FCC - Federal Communications Commission, a United States government agency.

Form 10-K - The combined Annual Report on Form 10-K for the year ended December 31, 2012, filed by Ameren, Ameren Missouri, and Ameren Illinois with the SEC.

IPH - Illinois Power Holdings, LLC, an indirect wholly owned subsidiary of Dynegy.

Medina Valley - AmerenEnergy Medina Valley Cogen, LLC, an AER subsidiary through March 13, 2013, which owned a 40-megawatt natural gas-fired electric energy center that was sold in February 2012. This company was distributed from AER to Ameren on March 14, 2013.

MISO - In April 2013, Midwest Independent Transmission System Operator, Inc. changed its name to Midcontinent Independent System Operator, Inc.

New AER - A limited liability company to be formed as a direct wholly owned subsidiary of AER. New AER will be acquired by IPH and will include substantially all of the assets and liabilities of AER, except for certain assets and liabilities retained by Ameren.

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:

• completion of our divestiture of New AER and the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers;

• regulatory approvals, including from the FERC, the FCC, and the Illinois Pollution Control Board relating to, and the satisfaction or waiver of the conditions to, the divestiture of New AER and regulatory approvals from the FERC with respect to the sale of Elgin, Gibson City and Grand Tower gas-fired energy centers;

• Ameren's exit from the Merchant Generation business, which could result in additional impairments of long-lived assets, disposal-related losses, contingencies, reduction of existing deferred tax assets, or could have other adverse impacts on the financial condition, results of operations and liquidity of Ameren;

• regulatory, judicial, or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the outcome of Ameren Illinois' natural gas rate case filed in 2013; the court appeals of Ameren Missouri's and Ameren Illinois' electric rate orders issued 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;

• the effect of Ameren Illinois participating in a 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;

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

• changes in laws and other governmental actions, including monetary, fiscal, and tax policies, such as changes that result in our being unable to claim all or a portion of the cash tax benefits that are expected to result from the divestiture of AER;

• 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

1

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, which may have a significant effect on the financial condition of Ameren's Merchant Generation segment;

• 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, including liquidity concerns for Ameren's Merchant Generation business, and specifically for Genco, whose ability to borrow additional funds from external, third-party sources is restricted;

• 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 additional nuclear generation at its Callaway energy center;

• operation of Ameren Missouri's Callaway energy center, including planned, unplanned and refueling outages, and future decommissioning costs;

• the effects of strategic initiatives, including mergers, acquisitions and divestitures, including the divestiture of the Merchant Generation business, 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 and discharges, 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 energy centers, 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 agreements, and financial instruments;

• the cost and availability of transmission capacity for the energy generated by Ameren's and Ameren Missouri's energy centers or required to satisfy energy sales made by Ameren or Ameren Missouri;

• 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.

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF INCOME (LOSS)

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

	Three months ended March 31,
	2013			2012
Operating Revenues:
Electric	$	1,088		$	1,064
Gas	387			348
Total operating revenues	1,475			1,412
Operating Expenses:
Fuel	213			181
Purchased power	151			209
Gas purchased for resale	230			215
Other operations and maintenance	399			369
Depreciation and amortization	175			167
Taxes other than income taxes	122			113
Total operating expenses	1,290			1,254
Operating Income	185			158
Other Income and Expenses:
Miscellaneous income	15			17
Miscellaneous expense	8			15
Total other income	7			2
Interest Charges	101			98
Income Before Income Taxes	91			62
Income Taxes	35			23
Income from Continuing Operations	56			39
Loss from Discontinued Operations, Net of Taxes (Note 2)	(199		)	(442		)
Net Loss	(143		)	(403		)
Less: Net Income (Loss) Attributable to Noncontrolling Interests:
Continuing Operations	2			2
Discontinued Operations	—			(2		)
Net Income (Loss) Attributable to Ameren Corporation:
Continuing Operations	54			37
Discontinued Operations	(199		)	(440		)
Net Loss Attributable to Ameren Corporation	$	(145	)	$	(403	)
Earnings (Loss) per Common Share – Basic and Diluted:
Continuing Operations	$	0.22		$	0.15
Discontinued Operations	(0.82		)	(1.81		)
Net Loss per Common Share – Basic and Diluted	$	(0.60	)	$	(1.66	)
Dividends per Common Share	$	0.40		$	0.40
Average Common Shares Outstanding	242.6			242.6

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

3

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Unaudited) (In millions)

	Three months ended March 31, 2013
	2013			2012
Net Income from Continuing Operations	$	56		$	39
Other Comprehensive Income, Net of Taxes	—			—
Comprehensive Income from Continuing Operations	56			39
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling            Interests	2			2
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation	54			37
Net Loss from Discontinued Operations	(199		)	(442		)
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Taxes	(7		)	15
Comprehensive Loss from Discontinued Operations	(206		)	(427		)
Less: Comprehensive Loss from Discontinued Operations Attributable to Noncontrolling            Interest	—			(2		)
Comprehensive Loss from Discontinued Operations Attributable to Ameren Corporation	(206		)	(425		)
Comprehensive Loss Attributable to Ameren Corporation	$	(152	)	$	(388	)

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

4

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

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

	March 31, 2013			December 31, 2012
ASSETS
Current Assets:
Cash and cash equivalents	$	161		$	184
Accounts receivable – trade (less allowance for doubtful accounts of $22 and $17, respectively)	479			354
Unbilled revenue	262			291
Miscellaneous accounts and notes receivable	70			71
Materials and supplies	461			570
Mark-to-market derivative assets	27			23
Current regulatory assets	196			247
Current accumulated deferred income taxes, net	80			160
Other current assets	60			75
Current assets of discontinued operations	1,500			1,600
Total current assets	3,296			3,575
Property and Plant, Net	15,408			15,348
Investments and Other Assets:
Nuclear decommissioning trust fund	437			408
Goodwill	411			411
Intangible assets	16			14
Regulatory assets	1,719			1,785
Other assets	665			668
Total investments and other assets	3,248			3,286
TOTAL ASSETS	$	21,952		$	22,209
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	355		$	355
Accounts and wages payable	341			533
Taxes accrued	91			50
Interest accrued	111			89
Customer deposits	110			107
Mark-to-market derivative liabilities	73			92
Current regulatory liabilities	135			100
Other current liabilities	163			168
Current liabilities of discontinued operations	1,198			1,166
Total current liabilities	2,577			2,660
Long-term Debt, Net	5,803			5,802
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	3,235			3,166
Accumulated deferred investment tax credits	68			70
Regulatory liabilities	1,667			1,589
Asset retirement obligations	380			375
Pension and other postretirement benefits	1,113			1,138
Other deferred credits and liabilities	593			642
Total deferred credits and other liabilities	7,056			6,980
Commitments and Contingencies (Notes 2, 3, 9, 10 and 11)
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	5,614			5,616
Retained earnings	764			1,006
Accumulated other comprehensive gain (loss)	(15		)	(8		)
Total Ameren Corporation stockholders’ equity	6,365			6,616
Noncontrolling Interests	151			151
Total equity	6,516			6,767
TOTAL LIABILITIES AND EQUITY	$	21,952		$	22,209

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

5

AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Three months ended March 31,
	2013			2012
Cash Flows From Operating Activities:
Net loss	$	(143	)	$	(403	)
Loss from discontinued operations, net of taxes	199			442
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	166			156
Amortization of nuclear fuel	20			21
Amortization of debt issuance costs and premium/discounts	6			4
Deferred income taxes and investment tax credits, net	40			30
Allowance for equity funds used during construction	(8		)	(9		)
Stock-based compensation costs	9			8
Other	(3		)	(5		)
Changes in assets and liabilities:
Receivables	(95		)	93
Materials and supplies	127			79
Accounts and wages payable	(127		)	(208		)
Taxes accrued	41			22
Assets, other	52			19
Liabilities, other	29			23
Pension and other postretirement benefits	3			41
Counterparty collateral, net	26			(9		)
Net cash provided by operating activities - continuing operations	342			304
Net cash provided by operating activities - discontinued operations	37			79
Net cash provided by operating activities	379			383
Cash Flows From Investing Activities:
Capital expenditures	(275		)	(245		)
Nuclear fuel expenditures	(11		)	(38		)
Purchases of securities – nuclear decommissioning trust fund	(35		)	(109		)
Sales and maturities of securities – nuclear decommissioning trust fund	32			102
Other	(2		)	(2		)
Net cash used in investing activities - continuing operations	(291		)	(292		)
Net cash used in investing activities - discontinued operations	(12		)	(19		)
Net cash used in investing activities	(303		)	(311		)
Cash Flows From Financing Activities:
Dividends on common stock	(97		)	(90		)
Dividends paid to noncontrolling interest holders	(2		)	(2		)
Short-term debt, net	—			(22		)
Advances received for construction	—			1
Net cash used in financing activities - continuing operations	(99		)	(113		)
Net cash used in financing activities - discontinued operations	—			—
Net cash used in financing activities	(99		)	(113		)
Net change in cash and cash equivalents	(23		)	(41		)
Cash and cash equivalents at beginning of year	184			248
Cash and cash equivalents at end of period	$	161		$	207
Noncash financing activity – dividends on common stock	$	—		$	(7	)

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

6

UNION ELECTRIC COMPANY

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)

	Three Months Ended March 31,
	2013		2012
Operating Revenues:
Electric	$	732	$	636
Gas	64		55
Total operating revenues	796		691
Operating Expenses:
Fuel	213		180
Purchased power	26		20
Gas purchased for resale	37		32
Other operations and maintenance	221		202
Depreciation and amortization	111		108
Taxes other than income taxes	77		71
Total operating expenses	685		613
Operating Income	111		78
Other Income and Expenses:
Miscellaneous income	14		15
Miscellaneous expense	5		3
Total other income	9		12
Interest Charges	60		56
Income Before Income Taxes	60		34
Income Taxes	19		12
Net Income	41		22
Other Comprehensive Income	—		—
Comprehensive Income	$	41	$	22
Net Income	$	41	$	22
Preferred Stock Dividends	1		1
Net Income Available to Common Stockholder	$	40	$	21

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

7

UNION ELECTRIC COMPANY

BALANCE SHEET

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

	March 31, 2013		December 31, 2012
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	148
Advances to money pool	—		24
Accounts receivable – trade (less allowance for doubtful accounts of $8 and $5, respectively)	202		161
Accounts receivable – affiliates	6		4
Unbilled revenue	151		145
Miscellaneous accounts and notes receivable	49		48
Materials and supplies	375		397
Current regulatory assets	144		163
Other current assets	51		69
Total current assets	979		1,159
Property and Plant, Net	10,152		10,161
Investments and Other Assets:
Nuclear decommissioning trust fund	437		408
Intangible assets	16		14
Regulatory assets	832		852
Other assets	451		449
Total investments and other assets	1,736		1,723
TOTAL ASSETS	$	12,867	$	13,043
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	205	$	205
Borrowings from money pool	5		—
Accounts and wages payable	153		345
Accounts payable – affiliates	65		66
Taxes accrued	66		28
Interest accrued	53		60
Current regulatory liabilities	23		18
Other current liabilities	86		77
Total current liabilities	656		799
Long-term Debt, Net	3,801		3,801
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	2,426		2,443
Accumulated deferred investment tax credits	63		64
Regulatory liabilities	968		917
Asset retirement obligations	351		346
Pension and other postretirement benefits	452		461
Other deferred credits and liabilities	146		158
Total deferred credits and other liabilities	4,406		4,389
Commitments and Contingencies (Notes 3, 9, 10 and 11)
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	1,556		1,556
Preferred stock not subject to mandatory redemption	80		80
Retained earnings	1,857		1,907
Total stockholders’ equity	4,004		4,054
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	12,867	$	13,043

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

8

UNION ELECTRIC COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Three months ended March 31,
	2013			2012
Cash Flows From Operating Activities:
Net income	$	41		$	22
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	104			100
Amortization of nuclear fuel	20			21
Amortization of debt issuance costs and premium/discounts	2			2
Deferred income taxes and investment tax credits, net	(8		)	2
Allowance for equity funds used during construction	(7		)	(8		)
Changes in assets and liabilities:
Receivables	(50		)	61
Materials and supplies	22			(26		)
Accounts and wages payable	(139		)	(136		)
Taxes accrued	38			39
Assets, other	38			13
Liabilities, other	5			—
Pension and other postretirement benefits	2			17
Net cash provided by operating activities	68			107
Cash Flows From Investing Activities:
Capital expenditures	(137		)	(157		)
Nuclear fuel expenditures	(11		)	(38		)
Money pool advances, net	24			—
Purchases of securities – nuclear decommissioning trust fund	(35		)	(109		)
Sales and maturities of securities – nuclear decommissioning trust fund	32			102
Other	(2		)	(2		)
Net cash used in investing activities	(129		)	(204		)
Cash Flows From Financing Activities:
Dividends on common stock	(90		)	(100		)
Dividends on preferred stock	(1		)	(1		)
Money pool borrowings, net	5			—
Net cash used in financing activities	(86		)	(101		)
Net change in cash and cash equivalents	(147		)	(198		)
Cash and cash equivalents at beginning of year	148			201
Cash and cash equivalents at end of period	$	1		$	3

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

9

AMEREN ILLINOIS COMPANY

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)

	Three months ended March 31,
	2013			2012
Operating Revenues:
Electric	$	360		$	431
Gas	324			293
Total operating revenues	684			724
Operating Expenses:
Purchased power	127			190
Gas purchased for resale	193			183
Other operations and maintenance	176			168
Depreciation and amortization	61			55
Taxes other than income taxes	42			39
Total operating expenses	599			635
Operating Income	85			89
Other Income and Expenses:
Miscellaneous income	1			1
Miscellaneous expense	3			11
Total other expense	(2		)	(10		)
Interest Charges	31			33
Income Before Income Taxes	52			46
Income Taxes	20			18
Net Income	32			28
Other Comprehensive Loss, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(1) and $-, respectively	(1		)	(1		)
Comprehensive Income	$	31		$	27
Net Income	$	32		$	28
Preferred Stock Dividends	1			1
Net Income Available to Common Stockholder	$	31		$	27

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

10

AMEREN ILLINOIS COMPANY

BALANCE SHEET

(Unaudited) (In millions)

	March 31, 2013		December 31, 2012
ASSETS
Current Assets:
Cash and cash equivalents	$	93	$	—
Advances to money pool	5		—
Accounts receivable – trade (less allowance for doubtful accounts of $14 and $12, respectively)	274		182
Accounts receivable – affiliates	13		10
Unbilled revenue	111		146
Miscellaneous accounts receivable	21		22
Materials and supplies	86		173
Current regulatory assets	52		84
Current accumulated deferred income taxes, net	56		85
Other current assets	36		47
Total current assets	747		749
Property and Plant, Net	5,117		5,052
Investments and Other Assets:
Tax receivable – Genco	38		39
Goodwill	411		411
Regulatory assets	887		934
Other assets	88		97
Total investments and other assets	1,424		1,481
TOTAL ASSETS	$	7,288	$	7,282
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	150	$	150
Borrowings from money pool	—		24
Accounts and wages payable	151		146
Accounts payable – affiliates	74		86
Taxes accrued	21		18
Interest accrued	41		22
Customer deposits	86		85
Mark-to-market derivative liabilities	49		77
Current environmental remediation	44		37
Current regulatory liabilities	113		82
Other current liabilities	63		70
Total current liabilities	792		797
Long-term Debt, Net	1,577		1,577
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,046		1,025
Accumulated deferred investment tax credits	5		5
Regulatory liabilities	699		672
Pension and other postretirement benefits	396		406
Environmental remediation liabilities	211		216
Other deferred credits and liabilities	146		183
Total deferred credits and other liabilities	2,503		2,507
Commitments and Contingencies (Notes 3, 9 and 10)
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	376		360
Accumulated other comprehensive income	13		14
Total stockholders’ equity	2,416		2,401
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	7,288	$	7,282

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

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AMEREN ILLINOIS COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Three months ended March 31,
	2013			2012
Cash Flows From Operating Activities:
Net income	$	32		$	28
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	60			52
Amortization of debt issuance costs and premium/discounts	3			2
Deferred income taxes and investment tax credits, net	50			55
Other	(1		)	(2		)
Changes in assets and liabilities:
Receivables	(58		)	35
Materials and supplies	105			103
Accounts and wages payable	9			(16		)
Taxes accrued	3			—
Assets, other	16			2
Liabilities, other	24			26
Pension and other postretirement benefits	1			15
Counterparty collateral, net	27			(11		)
Net cash provided by operating activities	271			289
Cash Flows From Investing Activities:
Capital expenditures	(133		)	(86		)
Money pool advances, net	(5		)	—
Net cash used in investing activities	(138		)	(86		)
Cash Flows From Financing Activities:
Dividends on common stock	(15		)	(37		)
Dividends on preferred stock	(1		)	(1		)
Money pool borrowings, net	(24		)	—
Advances received for construction	—			1
Net cash used in financing activities	(40		)	(37		)
Net change in cash and cash equivalents	93			166
Cash and cash equivalents at beginning of year	—			21
Cash and cash equivalents at end of period	$	93		$	187

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

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AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY

AMEREN ILLINOIS COMPANY

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

March 31, 2013

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 its equity interests in 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, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes.

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

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Immediately prior to Ameren’s entry into the transaction agreement with IPH, on March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. Ameren has commenced a sale process for these three gas-fired energy centers and expects a third-party sale to be completed during 2013. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding these divestitures. As a result of the transaction agreement with IPH and Ameren’s plan to sell its Elgin, Gibson City, and Grand Tower gas-fired energy centers, Ameren determined that New AER and the Elgin, Gibson City,

and Grand Tower gas-fired energy centers qualified for discontinued operations presentation. Therefore, Ameren has segregated New AER’s and the Elgin, Gibson City, and Grand Tower gas-fired energy centers’ operating results, assets, and liabilities and presented them separately as discontinued operations for all periods presented in this report. Unless otherwise noted, these notes to Ameren’s financial statements have been revised to exclude discontinued operations for all periods presented. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding that presentation.

The financial statements of Ameren 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.

During preparation of the 2012 annual statements of cash flows, it was identified that Ameren’s and Ameren Missouri’s 2012 interim statements of cash flows incorrectly classified certain activity from the nuclear decommissioning trust fund. Although not material, operating cash flows were overstated by $14 million, $26 million, and $49 million through the year-to-date first, second, and third quarters of 2012, respectively. The overstated operating cash flows resulted in the investing cash flows being understated by the same amounts. The 2012 first quarter cash flows for Ameren and Ameren Missouri have been revised in this report to correct for this error. The 2012 statements of cash flows for the second and third quarters of 2012 will be revised to correct for this error in the Ameren and Ameren Missouri 2013 second and third quarter reports.

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three months ended March 31, 2013, and 2012. The number of dilutive restricted stock shares and performance share units had an immaterial impact on earnings per share.

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Stock-based Compensation

A summary of nonvested shares as of March 31, 2013, and changes during the three months ended March 31, 2013, under the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

	Performance Share Units
	Share Units		Weighted-average Fair Value Per Unit at Grant Date
Nonvested at January 1, 2013	1,192,487		$	33.56
Granted(a)	832,034		31.19
Forfeitures	(5,456	)	32.67
Vested(b)	(122,671	)	31.19
Nonvested at March 31, 2013	1,896,394		$	32.68

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2013 under the 2006 Plan.

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

The fair value of each share unit awarded in January 2013 under the 2006 Plan was determined to be $31.19. That amount was based on Ameren’s closing common share price of $30.72 at December 31, 2012, 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, 2013. 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 0.36%, volatility of 12% to 21% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.

Intangible Assets

Ameren and Ameren Missouri classify emission allowances and renewable energy credits as intangible assets. Ameren Illinois consumes renewable energy credits as they are purchased through the IPA procurement process and expenses them immediately. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

At March 31, 2013, 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 Ameren’s and Ameren Missouri’s renewable energy credits was $16 million and $16 million, respectively, at March 31, 2013. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $14 million and $14 million, respectively, at December 31, 2012.

Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. In accordance with MoPSC's 2012 electric rate order, almost all of Ameren Missouri's amortization of intangible assets is deferred as a regulatory asset pending future recovery from customers through rates. 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, and Ameren Illinois, during the three months ended March 31, 2013, and 2012.

		Three Months
		2013		2012
Ameren Missouri	$	(a)	$	(a)
Ameren Illinois		4		(a)
Ameren	$	4	$	(a)

(a) Less than $1 million.

Excise Taxes

Excise taxes levied on us are reflected on Ameren Missouri electric customer bills and on 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 months ended March 31, 2013, and 2012:

	Three Months
	2013		2012
Ameren Missouri	$	33	$	27
Ameren Illinois	22		18
Ameren	$	55	$	45

Uncertain Tax Positions

The amount of unrecognized tax benefits as of March 31, 2013, was $190 million, $126 million, and $4 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The amount of unrecognized tax benefits (detriments) as of March 31, 2013, that would impact the effective tax rate, if recognized, was $48 million, $1 million, and $(1) million for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The Ameren amount increased

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by $47 million in the first three months of 2013. This increase was primarily due to uncertainty related to the historical computation of Ameren’s tax basis in its stock investment in AER.

Ameren’s federal income tax returns for the years 2007 through 2010 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2011 is currently under examination.

It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the next 12 months for the years 2007 through 2010. This settlement, primarily related to uncertain tax positions for capitalization versus currently deductible repair expense and research tax deductions, is expected to result in a decrease in uncertain tax benefits of approximately $126 million, $110 million, and $5 million for Ameren, Ameren Missouri and Ameren Illinois, respectively. In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe any such increases or decreases, including the decrease from the reasonably possible IRS Appeals

Office settlement discussed above, would be material to their results of operations, financial position, or liquidity.

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.

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri, and Ameren Illinois increased compared to December 31, 2012, to reflect the accretion of obligations to their fair values.

Based on the transaction agreement to divest New AER to IPH, Ameren will retain the AROs associated with the Meredosia and Hutsonville energy centers. Therefore, these AROs are classified as continuing operations. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

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. A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren for the three months ended March 31, 2013, and 2012, is shown below:

	Three Months
	2013			2012
Ameren:
Noncontrolling interests, beginning of period (a)	$	151		$	149
Net income from continuing operations attributable to noncontrolling interests	2			2
Net income (loss) from discontinued operations attributable to noncontrolling interests	—			(2		)
Dividends paid to noncontrolling interest holders	(2		)	(2		)
Noncontrolling interests, end of period (a)	$	151		$	147

(a) Includes the 20% EEI ownership interest not owned by Ameren. The assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Current assets of discontinued operations” and “Current liabilities of discontinued operations,” however, the 20% ownership interest not owned by Ameren was included in “Noncontrolling interests” on Ameren’s March 31, 2013, and December 31, 2012 balance sheet. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

Accounting and Reporting Developments

The following is a summary of recently adopted authoritative accounting guidance that could impact the Ameren Companies.

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation

of the amended guidance did not affect the Ameren Companies’ results of operations, financial position, or liquidity.

In February 2013, FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. This guidance was effective for the Ameren Companies beginning in the first quarter of 2013. The implementation of this amendment did not affect the Ameren Companies’ results of operations, financial position, or liquidity. The only amounts reclassified out of accumulated OCI for the Ameren Companies related to pension and other postretirement

15

plan activity. These amounts were immaterial during the first quarter of 2013 and 2012, and therefore no additional disclosures required.

Disclosures about Offsetting Assets and Liabilities

In December 2011, FASB issued additional authoritative guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The amendments did not affect the Ameren Companies’ results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. The Ameren Companies adopted this guidance for the first quarter of 2013. See Note 7 - Derivative Financial Instruments for the required additional disclosures.

NOTE 2 - DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS

Transaction Agreement with IPH

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Under the terms of the transaction agreement, AER will effect a reorganization that will, among other things, transfer substantially all of the assets and liabilities of AER, other than (i) any outstanding debt obligations of AER to Ameren or its other subsidiaries, except for certain intercompany balances discussed below, (ii) all of the issued and outstanding equity interests in Medina Valley, which were distributed to Ameren in March 2013, (iii) the assets and liabilities associated with Genco’s Meredosia, Hutsonville, Elgin, Gibson City, and Grand Tower energy centers, (iv) the obligations relating to Ameren's single-employer pension and postretirement benefit plans, and (v) the deferred tax positions associated with Ameren's ownership of these retained assets and liabilities, to New AER. IPH will acquire all of the equity interests in New AER.

Ameren will retain the pension and postretirement benefit obligations associated with current and former employees of AER that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan. This noncurrent obligation is reflected on Ameren’s consolidated balance sheet as “Pension and other postretirement benefits.” IPH will assume the pension and other postretirement benefit obligations associated with EEI’s current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. The obligations to be assumed by IPH are estimated at $39 million at March 31, 2013. IPH will also acquire the estimated $15 million asset at March 31, 2013, relating to the overfunded status of one of EEI’s postretirement plans.

Ameren will retain Genco’s Meredosia and Hutsonville energy centers, which are no longer in operation and had an immaterial property and plant asset balance as of March 31, 2013. Ameren will also retain AROs associated with these energy centers, estimated at $27 million as of March 31, 2013. All other AROs associated with AER will be assumed by either IPH or the third-party buyer of the Grand Tower energy center. Upon the transaction agreement closing, with the exception of certain agreements, such as supply obligations to Ameren Illinois, a note from New AER to Ameren relating to cash collateral that will remain outstanding at closing, and Genco money pool advances, all intercompany agreements and debt between AER and its subsidiaries, on the one hand, and Ameren and its affiliates, on the other hand, will be either retained or cancelled by Ameren, without any cost or obligation to IPH or New AER and its subsidiaries. Immediately prior to the transaction agreement closing, the cash collateral provided to New AER by Ameren through money pool borrowings will be converted to a note payable to Ameren which will be payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced.

Genco's $825 million in aggregate principal amount of senior notes will remain outstanding following the transaction agreement closing and will continue to be solely obligations of Genco. Pursuant to the transaction agreement, in addition to the cash paid to Genco for the Elgin, Gibson City, and Grand Tower energy center sale, Ameren will cause $85 million of cash to be retained at New AER.

As a condition to the transaction agreement, Genco exercised the amended put option agreement for the sale of the Elgin, Gibson City and Grand Tower gas-fired energy centers to Medina Valley. Ameren has commenced a sale process for these three energy centers and expects a third-party sale will be completed during 2013.

Completion of the New AER sale to IPH is subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC. On April 16, 2013, AER and Dynegy filed with FERC an application for approval of the divestiture of New AER and Genco’s sale of the Elgin, Gibson City and Grand Tower gas-fired energy centers to Medina Valley. As a condition to IPH’s obligation to complete the transaction, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS. AER and Dynegy filed a transfer request with the Illinois Pollution Control Board on May 2, 2013. Ameren’s and IPH’s obligation to complete the transaction is also subject to other customary closing conditions, including the material accuracy of each company’s representations and warranties and the compliance, in all material respects, with each company’s covenants. The transaction agreement contains customary representations and warranties of Ameren and IPH, including representations and warranties of Ameren with respect to the business being sold. The transaction agreement also contains customary covenants of Ameren and IPH, including the covenant of Ameren that AER will be operated in the ordinary course prior to the closing.

16

Ameren expects the closing of the New AER divestiture to IPH will occur in the fourth quarter of 2013. If the closing does not occur on or before March 14, 2014, subject to a one-month extension to obtain FERC approval, either party may elect to terminate the transaction agreement if the inability to close the transaction by such date is not the result of the failure of the terminating company to fulfill any of its obligations under the transaction agreement.

Amended Put Option Agreement, Asset Purchase Agreement and Guaranty

See Note 9 - Related Party Transactions for additional information regarding the original put option agreement between Genco and AERG that was entered into on March 28, 2012.

Prior to entry into the transaction agreement with IPH as discussed above, (i) the original put option agreement between Genco and AERG was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley and (ii) Genco exercised its option under the amended put option agreement to sell the Elgin, Gibson City and Grand Tower gas-fired energy centers to Medina Valley. As a result, on March 14, 2013, Genco received an initial payment of $100 million in accordance with the terms of the amended put option agreement. Genco advanced the initial payment amount it received into the non-state-regulated subsidiaries money pool. In connection with the amended put option agreement, Ameren's guaranty, dated March 28, 2012, was modified to replace all references to AERG with references to Medina Valley.

Pursuant to the amended put option agreement, Genco and Medina Valley entered into an asset purchase agreement, dated March 14, 2013. Genco and Medina Valley have engaged three appraisers to conduct a fair market valuation of the Elgin, Gibson City and Grand Tower gas-fired energy centers, which valuations will be averaged and subject to adjustment at the closing of the asset purchase agreement to reflect the assets and liabilities associated with the Elgin, Gibson City and Grand Tower gas-fired

energy centers. At the asset purchase agreement closing, Genco will receive an additional amount equal to the greater of (i) $33 million, or (ii) the appraised value of the Elgin, Gibson City and Grand Tower gas-fired energy centers less the initial payment of $100 million, for a total purchase price of at least $133 million, and Genco will sell and transfer to Medina Valley all of its rights in the Elgin, Gibson City and Grand Tower gas-fired energy centers as a condition to the transaction agreement. If these gas-fired energy centers are subsequently sold by Medina Valley within two years of the asset purchase agreement closing, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the amounts previously paid to Genco. Ameren has commenced a sale process for these three energy centers and expects a third-party sale will be completed during 2013. Should FERC approval not be obtained and the transfer of the Elgin, Gibson City, and Grand Tower energy centers cannot be completed, Genco will be required to return to Medina Valley the initial payment received in March 2013.

The asset purchase agreement contains customary representations, warranties and covenants of Genco and Medina Valley. The consummation of the transactions contemplated by the asset purchase agreement is subject to certain conditions, including the receipt of FERC approval and other customary conditions.

Discontinued Operations Presentation

As of March 14, 2013, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation and, therefore, were classified separately in Ameren’s consolidated financial statements as discontinued operations for all periods presented in this report. Ameren concluded that New AER and collectively the Elgin, Gibson City, and Grand Tower gas-fired energy centers are two separate disposal groups. Both disposal groups have been aggregated in the disclosures below. Each disposal group was measured at fair value on a nonrecurring basis with inputs that are classified as Level 3 within the fair value hierarchy.

The following table presents the components of discontinued operations in Ameren's consolidated statement of income (loss) for the three months ended March 31, 2013, and 2012:

	Three Months
	2013				2012
Operating revenues	$	264			$	246
Operating expenses	(415		)	(a)	(826		)	(b)
Operating (loss)	(151		)		(580		)
Other income (loss)	(2		)		—
Interest charges	(11		)		(15		)
Loss before income taxes	(164		)		(595		)
Income tax (expense) benefit	(35		)		153
Loss from discontinued operations, net of taxes	$	(199	)		$	(442	)

(a) Includes a noncash pretax impairment charge of $155 million to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell.

(b) Includes 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 under held and used accounting guidance.

17

As the New AER disposal group met the discontinued operations criteria at March 31, 2013, Ameren evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value of the disposal group, less cost to sell. The fair value was based on the terms of Ameren’s agreement to divest New AER to IPH. Ameren will receive no cash proceeds from IPH for the divestiture of New AER. Ameren recorded a pretax charge to earnings of $155 million for the three months ended March 31, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. The impairment loss was recorded in “Operating expenses” within the components of the discontinued operations statement of income (loss) with a corresponding reduction in “Property and Plant, net” within the components of the discontinued operations balance sheet. Ameren estimated the impairment loss of the disposal group based on the estimated fair value pursuant to the terms of the transaction agreement with IPH, using information currently available, and assuming an expected fourth quarter 2013 closing. Actual operating results, derivative market values, capital expenditures and other items will impact the ultimate loss recognized to reduce the carrying value of the New AER disposal group to its actual fair value less cost to sell, which will be recorded in discontinued operations after all of the information becomes available. In addition, any curtailment gain related to Ameren's pension and postretirement plans will be recorded when the related employees terminate employment with Ameren. The ultimate impairment loss may differ materially from the estimated loss recorded in the first quarter of 2013.

Ameren recognized the excess of the tax basis over the financial reporting basis of its stock investment in AER when it became apparent, in the three months ended March 31, 2013, that the temporary difference would reverse. This change in basis resulted in a discontinued operations deferred tax expense of $98 million, which was partially offset by the expected tax benefits of $63 million related to the pretax loss from discontinued operations including the impairment charge recorded in the first quarter of 2013. The final tax basis of the AER disposal group and the related tax benefit resulting from the transaction agreement with IPH are dependent upon taxable losses utilized

by the disposal group through the closing and the resolution of tax matters under audit, including the adoption of recently issued guidance from the IRS related to tangible property repairs and other matters. As a result, tax expense and benefits realized in discontinued operations may differ materially from those recorded as of March 31, 2013.

As the Elgin, Gibson City, and Grand Tower energy center disposal group met the discontinued operations criteria at March 31, 2013, we evaluated whether any impairment existed by comparing the disposal group’s carrying value to the fair value of the disposal group less cost to sell. The fair value was based on the appraised value of these three gas-fired energy centers. In December 2012, Ameren recorded a noncash long-lived asset impairment charge to reduce the carrying value of AER’s energy centers, including the Elgin, Gibson City, and Grand Tower energy centers, to their estimated fair values under the accounting guidance for held and used assets. An immaterial impairment was recorded by Ameren for the three gas-fired energy centers during the three months ended March 31, 2013, as the December 2012 held and used asset impairment charge reduced these energy centers’ disposal group carrying value to their estimated fair value of $133 million. Ameren does not expect to have significant continuing involvement or material cash flows with the Elgin, Gibson City, and Grand Tower energy centers after their divestiture.

Effective with its conclusion that the New AER disposal group and the Elgin, Gibson City and Grand Tower energy centers’ disposal group each met the criteria for discontinued operations presentation, Ameren suspended recording depreciation on these assets in March 2013.

Interest on Genco’s senior notes, which are being assumed by IPH, are included in the “Interest charges” component within the discontinued operations line item in the statement of income (loss). Ameren did not allocate corporate interest to the disposal groups. Additionally, general corporate overhead expenses originally allocated to the disposal groups were classified as expenses of continuing operations.

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The following table presents the carrying amounts of the components of assets and liabilities segregated on Ameren's consolidated balance sheets as discontinued operations at March 31, 2013, and December 31, 2012:

	March 31, 2013		December 31, 2012
Current assets of discontinued operations
Cash and cash equivalents	$	25	$	25
Accounts receivable and unbilled revenue	103		102
Materials and supplies	117		134
Mark-to-market derivative assets	101		102
Property and plant, net	607		748
Accumulated deferred income taxes, net	412		373
Other assets	135		116
Total current assets of discontinued operations	$	1,500	$	1,600
Current liabilities of discontinued operations
Accounts payable and other current obligations	$	138	$	133
Mark-to-market derivative liabilities	82		63
Long-term debt, net	824		824
Asset retirement obligations	86		78
Pension and other postretirement benefits	39		40
Other liabilities	29		28
Total current liabilities of discontinued operations	$	1,198	$	1,166
Accumulated other comprehensive gain(a)	$	12	$	19
Noncontrolling interest(b)	$	8	$	8

(a) Accumulated other comprehensive gain related to discontinued operations remains in “Accumulated other comprehensive gain (loss)” on Ameren’s March 31, 2013, and December 31, 2012, balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s balance sheet either before or at the closing of the New AER divestiture.

(b) The 20% ownership interest of EEI not owned by Ameren remains in “Noncontrolling interests” on Ameren’s March 31, 2013, and December 31, 2012, balance sheets. This noncontrolling interest will be removed from Ameren’s balance sheet at the closing of the New AER divestiture.

Ameren will have continuing transactions with New AER after the divestiture is complete. Ameren Illinois has power supply agreements with Marketing Company which are a result of the power procurement process in Illinois administered by the IPA as required by the Illinois Public Utilities Act. Ameren Illinois will continue to purchase power and purchase trade receivables as required by Illinois law, and Ameren will reflect these items as continuing operations after the divestiture occurs. Ameren Illinois and ATXI currently sell, and will continue to sell, transmission services to Marketing Company after the divestiture of New AER is completed. Also, upon the divestiture of New AER, subject to certain exceptions, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture and provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. IPH shall indemnify Ameren for any payments it makes pursuant to these credit support obligations. IPH’s indemnification obligation will be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH’s indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions). Immediately prior to the transaction agreement closing, the cash collateral provided to New AER by Ameren through money pool borrowings will be converted to a note payable to Ameren which will be payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced. Also, within 120

days after closing, a working capital adjustment will be finalized, which may result in a cash payment from Ameren to New AER. Ameren has determined that the continuing cash flows generated by these arrangements are not significant and, accordingly, are not deemed direct cash flows of the divested business. Additionally, these arrangements do not provide Ameren the ability to significantly influence the operating results of New AER after the divestiture is complete. See Note 9 - Related Party Transactions for additional information regarding existing transactions between Ameren and New AER.

For a period of up to 12 months following the closing, Ameren will provide certain transitional services to IPH. Such services will be provided at no charge for 90 days, subject to a $5 million limit; thereafter, services will be provided at cost, except for certain services that may be applied to the $5 million limit to the extent such limit has not been reached by the end of the 90 days period. The transitional services will be provided for six months after the closing and can be extended by IPH on a month-to-month basis for up to an additional six months.

See Note 10 - Commitments and Contingencies for information regarding amendments to the plant transfer agreements between both Genco and Ameren Illinois and AERG and Ameren Illinois as well as other AER related contingencies.

Genco Indenture Provisions

Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in

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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 March 31, 2013:

	Required Ratio	Actual Ratio
Restricted payment interest coverage ratio(a)	≥1.75	2.3
Additional indebtedness interest coverage ratio(b)	≥2.50	2.3
Additional indebtedness debt-to-capital ratio(b)	≤60%	50	%

(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. 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.

As shown in the table above, 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. During the first quarter of 2013, Genco’s interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and we expect the ratio to remain less than this minimum level through at least 2015. As a result, Genco’s ability to borrow additional funds from external third-party sources is restricted. 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. 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. As stated above, the transaction agreement requires Ameren to operate New AER, including Genco, in the ordinary course prior to the closing.

NOTE 3 - RATE AND REGULATORY MATTERS

Below is a summary of updates to 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

FAC Prudence Reviews

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.

Ameren Missouri disagrees with the MoPSC order's classification of these sales and believed 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 and a group of large industrial customers 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. A decision is expected to be issued in 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. 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 amount covered by the accounting authority order, if it is granted.

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The MoPSC’s FAC prudence review for the period from June 1, 2011, to September 30, 2012, was initiated on March 1, 2013. The MoPSC is expected to issue an order for this prudence review in 2013.

Illinois

IEIMA

In September 2012, the ICC issued an order in Ameren Illinois’ initial filing under the IEIMA’s performance-based formula rate framework. In October 2012, Ameren Illinois filed an appeal of the ICC’s initial filing order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013. Ameren Illinois believes the ICC incorrectly implemented the IEIMA by using an average capital structure as opposed to a year-end capital structure on the revenue requirement, the method it used for calculating the equity portion of Ameren Illinois' capital structure, the method for calculating interest and the average rate base rather than year-end rate base for the revenue requirement reconciliation.

In April 2012, Ameren Illinois submitted to the ICC an update filing under IEIMA. In December 2012, the ICC issued an order approving an Ameren Illinois electric delivery service revenue requirement of $765 million, based on 2011 recoverable costs and expected net plant additions for 2012. The delivery service rates became effective on January 1, 2013, and will be effective through the end of 2013. In January 2013, Ameren Illinois filed an appeal of the ICC's update filing order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013.

The ICC's orders in 2012 for Ameren Illinois’ initial and update rate filings jeopardize 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 slowing IEIMA capital spending with a corresponding negative effect on the job creation that the legislature sought to effectuate with the law. Ameren Illinois still intends to meet its IEIMA capital spending requirements.

On April 19, 2013, Ameren Illinois filed its annual electric delivery formula rate update with the ICC based on 2012 recoverable costs and expected net plant additions for 2013. Pending ICC approval, the update filing will result in a $30 million decrease in Ameren Illinois’ electric delivery revenue requirement beginning in January 2014. The filing includes a refund to customers of the 2012 revenue requirement reconciliation of approximately $50 million. An expected refund was recorded in 2012 as a regulatory liability on Ameren Illinois’ balance sheet. In the filing, the proposed refund is partially offset by an annual revenue requirement increase of approximately $20 million primarily due to increased recoverable costs over 2011 levels. The filing is based on an electric delivery service revenue requirement of $785 million, before consideration of the 2012 revenue requirement reconciliation refund. An ICC decision with respect to the April 2013 update filing is expected in December 2013 and will establish rates for 2014.

On March 14, 2013, the Illinois General Assembly passed legislation, which, if enacted, would result in certain amendments to the IEIMA that would modify its implementation. The passed legislation, Senate Bill 9, clarifies the provisions in the IEIMA that require the year-end rate base be used to calculate the revenue requirement reconciliation and that the interest applied to the revenue requirement reconciliation and return on equity collar adjustments would be consistent with the company’s weighted-average return calculated under the formula rate. Additionally, the legislation specifies the use of year-end capital structure for both the revenue requirement and the revenue requirement reconciliation. On May 5, 2013, the Illinois Governor vetoed this legislation. If this legislation is ultimately enacted through a legislative override in 2013, Ameren Illinois will submit revisions to its April 19, 2013 update filing based on the new law.

Federal

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. 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. In November 2012, a FERC administrative law judge issued an initial decision, which is now pending before FERC. The timing of a FERC decision is uncertain. Based on the administrative law judge's initial decision, Ameren and Ameren Illinois each has included on its balance sheet in “Current regulatory liabilities” as of March 31, 2013, an estimate of $9 million for the refund due to wholesale customers relating to billings from March 2011 through March 2013.

Ameren Illinois Electric Transmission Rate Refund

In July 2012, FERC issued an order with respect to 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 transmission formula rate, thereby inappropriately recovering a higher return on rate base from its electric transmission 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. After reviewing the FERC order and its calculation of the impact on electric transmission formula rates, Ameren Illinois concluded that no refund was warranted. Several wholesale customers filed a protest with FERC regarding Ameren's conclusion that no refund is 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

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in which that determination was made and the amount could be estimated.

Combined Construction and Operating License

In 2008, Ameren Missouri filed an application with the NRC for a COL for a new nuclear unit at Ameren Missouri's existing Callaway County, Missouri, 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 investment funds for the design, engineering, manufacturing, and sale of American-made small modular nuclear reactors. In April 2012, Ameren Missouri entered into an agreement with Westinghouse to exclusively support Westinghouse's application for the DOE's small modular nuclear 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. In November 2012, the DOE awarded investment funds for only one small modular reactor design, which was not the Westinghouse design, but also stated that additional investment funds would be awarded during 2013. Westinghouse continues to pursue investment funds from the DOE.

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 energy center 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 March 31, 2013, the DOE investment funds that would help support the COL application, and Ameren Missouri's 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. 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 is made.

NOTE 4 - 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 agreements, or commercial paper issuances.

The 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement were not utilized for borrowings during the three months ended March 31, 2013. As of March 31, 2013, based on letters of credit issued under the 2012 Credit Agreements, the aggregate amount of credit capacity available to Ameren (parent), Ameren Missouri and Ameren Illinois, collectively at March 31, 2013, was $2.06 billion.

Commercial Paper

Ameren did not have any commercial paper outstanding at March 31, 2013, or December 31, 2012. The average daily commercial paper balances outstanding during the three months ended March 31, 2013, and 2012, were $2 million and $84 million, respectively. The weighted-average interest rates during the three months ended March 31, 2013, and 2012, were 0.80% and 0.94%, respectively. The peak short-term commercial paper balances outstanding during the three months ended March 31, 2013, and 2012, were $21 million and $186 million, respectively. The peak interest rates during the three months ended March 31, 2013, and 2012, were 0.85% and 1.25%, respectively. Ameren Missouri and Ameren Illinois did not utilize their commercial paper programs during the three months ended March 31, 2013, and 2012.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants within the 2012 Credit Agreements. See Note 4 – Short-term Debt and Liquidity in the Form 10-K for a detailed description of these provisions.

The 2012 Credit Agreements 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 2012 Credit Agreements require each of Ameren, Ameren Missouri and Ameren Illinois to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of March 31, 2013, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2012 Credit Agreements, were 52%, 48% and 42%, for Ameren, Ameren Missouri and Ameren Illinois, respectively. In addition, under the 2012 Illinois Credit Agreement and by virtue of the cross-default provisions of the 2012 Missouri 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 2012 Illinois Credit Agreement. Ameren’s ratio as of March 31, 2013, was 5.1

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to 1.0. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2012 Credit Agreement. Ameren’s ratios, as discussed above, include both continuing and discontinued operations for the purposes of these calculations.

None of the Ameren Companies' credit agreements or financing arrangements contain credit rating triggers that would cause a 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 agreements at March 31, 2013.

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 2012 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 months ended March 31, 2013, was 0.11% (2012 - 0.11%).

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 2012 Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. AER, Genco, AERG and Marketing Company may participate in the non-state-regulated money pool through the closing of the divestiture transaction as detailed in Note 2 - Divestiture Transactions and Discontinued Operations. 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 months ended March 31, 2013, was 0.22% (2012 - 0.76%).

See Note 9 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three months ended March 31, 2013, and 2012.

NOTE 5 - LONG-TERM DEBT AND EQUITY FINANCINGS

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. 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 as of March 31, 2013, 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	4.7	$	4,304		≥2.5	128.1	$	2,454
Ameren Illinois	≥2.0	7.2		3,499	(d)	≥1.5	2.7		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.

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(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.

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 2012 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 and Ameren Illinois and certain other 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 dividend payments on its 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 March 31, 2013, Ameren Illinois’ ratio of common stock equity to total capitalization was 57%.

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.

Off-Balance-Sheet Arrangements

At March 31, 2013, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

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NOTE 6 - OTHER INCOME AND EXPENSES

The following table presents the components of “Other Income and Expenses” in the Ameren Companies’ statements of income (loss) for the three months ended March 31, 2013, and 2012:

	Three Months
	2013		2012
Ameren:(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	8	$	9
Interest income on industrial development revenue bonds	7		7
Other	—		1
Total miscellaneous income	$	15	$	17
Miscellaneous expense:
Donations	$	4	$	12	(b)
Other	4		3
Total miscellaneous expense	$	8	$	15
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	7	$	8
Interest income on industrial development revenue bonds	7		7
Total miscellaneous income	$	14	$	15
Miscellaneous expense:
Donations	$	2	$	2
Other	3		1
Total miscellaneous expense	$	5	$	3
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	1	$	1
Total miscellaneous income	$	1	$	1
Miscellaneous expense:
Donations	$	3	$	10	(b)
Other	—		1
Total miscellaneous expense	$	3	$	11

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

(b) Includes Ameren Illinois’ one-time $7.5 million donation to the Illinois Science and Energy Innovation Trust pursuant to the IEIMA as a result of Ameren Illinois’ 2012 participation in the formula ratemaking process.

NOTE 7 - 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.

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The following table presents open gross commodity contract volumes by commodity type as of March 31, 2013, and December 31, 2012:

	Quantity (in millions, except as indicated)
Commodity	Accrual & NPNS Contracts(a)		Other Derivatives(b)		Derivatives That Qualify for Regulatory Deferral(c)
	2013	2012	2013	2012	2013	2012
Coal (in tons)
Ameren Missouri & Ameren	91	96	(d)	(d)	(d)	(d)
Fuel oils (in gallons)(e)
Ameren Missouri & Ameren	(d)	(d)	(d)	(d)	67	26
Natural gas (in mmbtu)
Ameren Missouri	3	4	1	—	21	19
Ameren Illinois	12	16	(d)	(d)	137	128
Ameren	15	20	1	—	158	147
Power (in megawatthours)
Ameren Missouri	4	3	2	2	8	9
Ameren Illinois	19	21	(d)	(d)	12	14
Ameren	23	24	2	2	20	23
Renewable energy credits(f)
Ameren Missouri	3	3	(d)	(d)	(d)	(d)
Ameren Illinois	12	12	(d)	(d)	(d)	(d)
Ameren	15	15	(d)	(d)	(d)	(d)
Uranium (pounds in thousands)
Ameren Missouri & Ameren	4,950	5,142	(d)	(d)	480	446

(a) Accrual contracts include commodity contracts that do not qualify as derivatives. As of March 31, 2013, these contracts ran through December 2017, March 2015, September 2024, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively.

(b) As of March 31, 2013, these contracts ran through April 2013 and December 2014 for natural gas and power, respectively.

(c) As of March 31, 2013, these contracts ran through October 2015, March 2017, May 2032, and September 2014 for fuel oils, natural gas, power, and uranium, respectively.

(d) Not applicable.

(e) Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.

(f) A renewable energy credit is created for every one megawatthour of renewable energy generated. The Ameren Companies’ contracts include renewable energy credits from solar and wind-generated power.

Authoritative accounting 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 8 - 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 (loss) 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 (loss) 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 (loss) 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

26

did not elect to adopt this guidance for any eligible commodity contracts.

27

The following table presents the carrying value and balance sheet location of all derivative instruments as of March 31, 2013, and December 31, 2012:

	Balance Sheet Location		Ameren		Ameren Missouri		Ameren Illinois
2013
Derivative assets not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	MTM derivative assets	$	6	$	(b)	$	(b)
	Other current assets		—		6		—
	Other assets		4		4		—
Natural gas	MTM derivative assets		6		(b)		(b)
	Other current assets		—		1		5
	Other assets		2		1		1
Power	MTM derivative assets		15		(b)		(b)
	Other current assets		—		15		—
	Other assets		4		1		3
	Total assets	$	37	$	28	$	9
Derivative liabilities not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	MTM derivative liabilities	$	1	$	(b)	$	—
	Other current liabilities		—		1		—
	Other deferred credits and liabilities		2		2		—
Natural gas	MTM derivative liabilities		45		(b)		38
	Other current liabilities		—		7		—
	Other deferred credits and liabilities		34		5		29
Power	MTM derivative liabilities		25		(b)		11
	Other current liabilities		—		14		—
	Other deferred credits and liabilities		74		1		73
Uranium	MTM derivative liabilities		2		(b)		—
	Other current liabilities		—		2		—
	Total liabilities	$	183	$	32	$	151
2012
Derivative assets not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	MTM derivative assets	$	8	$	(b)	$	(b)
	Other current assets		—		8		—
	Other assets		4		4		—
Natural gas	MTM derivative assets		1		(b)		(b)
	Other current assets		—		—		1
	Other assets		1		1		—
Power	MTM derivative assets		14		(b)		(b)
	Other current assets		—		14		—
	Other assets		1		1		—
	Total assets	$	29	$	28	$	1
Derivative liabilities not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	MTM derivative liabilities	$	2	$	(b)	$	—
	Other current liabilities		—		2		—
	Other deferred credits and liabilities		2		2		—
Natural gas	MTM derivative liabilities		64		(b)		56
	Other current liabilities		—		8		—
	Other deferred credits and liabilities		45		7		38
Power	MTM derivative liabilities		25		(b)		21
	Other current liabilities		—		4		—
	Other deferred credits and liabilities		90		—		90
Uranium	MTM derivative liabilities		1		(b)		—
	Other current liabilities		—		1		—
	Other deferred credits and liabilities		1		1		—
	Total liabilities	$	230	$	25	$	205

(a) Includes derivatives subject to regulatory deferral.

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

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The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in regulatory assets or regulatory liabilities as of March 31, 2013, and December 31, 2012:

	Ameren			Ameren Missouri			Ameren Illinois
2013
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Fuel oils derivative contracts(a)	$	4		$	4		$	—
Natural gas derivative contracts(b)	(71		)	(10		)	(61		)
Power derivative contracts(c)	(79		)	2			(81		)
Uranium derivative contracts(d)	(2		)	(2		)	—
2012
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Fuel oils derivative contracts(a)	$	4		$	4		$	—
Natural gas derivative contracts(b)	(107		)	(14		)	(93		)
Power derivative contracts(c)	(99		)	12			(111		)
Uranium derivative contracts(d)	(2		)	(2		)	—

(a) 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 March 31, 2013. Current gains deferred as regulatory liabilities include $4 million and $4 million at Ameren and Ameren Missouri as of March 31, 2013, respectively. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of March 31, 2013, respectively.

(b) 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 March 31, 2013. Current gains deferred as regulatory liabilities include $6 million, $1 million, and $5 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2013. Current losses deferred as regulatory assets include $45 million, $7 million, and $38 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2013.

(c) Represents net gains (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 March 31, 2013. Current gains deferred as regulatory liabilities include $12 million and $12 million at Ameren and Ameren Missouri, respectively, as of March 31, 2013. Current losses deferred as regulatory assets include $21 million, $10 million, and $11 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2013.

(d) 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 March 31, 2013. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri as of March 31, 2013, respectively.

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

We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) 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.

Although Ameren had not previously elected to offset fair value amounts and collateral for derivative instruments executed with the same counterparty under the same master netting arrangement, authoritative accounting guidance, effective in the first quarter 2013, requires those amounts eligible to be offset to be presented both at the gross and net amounts. The following table provides the recognized gross derivative balances and the net amounts of those derivatives subject to an enforceable master netting arrangement or similar agreement as of March 31, 2013, and December 31, 2012:

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			Gross Amounts Not Offset in the Balance Sheet
	Gross Amounts Recognized in the Balance Sheet		Derivative Instruments		Cash Collateral Received/Posted(a)		Net Amount
2013
Commodity contracts eligible to be offset:
Assets:
Ameren	$	37	$	20	$	—	$	17
Ameren Missouri	28		15		—		13
Ameren Illinois	9		5		—		4
Liabilities:
Ameren	$	183	$	20	$	39	$	124
Ameren Missouri	32		15		8		9
Ameren Illinois	151		5		31		115
2012
Commodity contracts eligible to be offset:
Assets:
Ameren	$	29	$	10	$	—	$	19
Ameren Missouri	28		9		—		19
Ameren Illinois	1		1		$	—	—
Liabilities:
Ameren	$	230	$	10	$	65	$	155
Ameren Missouri	25		9		7		9
Ameren Illinois	205		1		58		146

(a) Cash collateral received reduces gross asset balances and cash collateral posted reduces gross liability balances.

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 groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of March 31, 2013, and December 31, 2012, if counterparty groups were to fail completely 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		Commodity Marketing Companies		Electric Utilities		Financial Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Total
2013
Ameren Missouri	$	1	$	1	$	1	$	10	$	3	$	—	$	16
Ameren Illinois	—		2		—		4		—		2		8
Ameren	$	1	$	3	$	1	$	14	$	3	$	2	$	24
2012
Ameren Missouri	$	—	$	2	$	3	$	14	$	3	$	—	$	22
Ameren Illinois	—		—		—		1		—		—		1
Ameren	$	—	$	2	$	3	$	15	$	3	$	—	$	23

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 Ameren Companies held no cash from counterparties based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements at March 31, 2013 and December 31, 2012. As of March 31, 2013, other collateral used to reduce exposure consisted of letters of credit of less than $1 million held by Ameren and Ameren Missouri. As of December 31, 2012, other collateral used to reduce exposure consisted of letters of credit of $1 million held by Ameren and Ameren Missouri.

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The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of March 31, 2013, and December 31, 2012:

	Affiliates		Commodity Marketing Companies		Electric Utilities		Financial Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Total
2013
Ameren Missouri	$	1	$	1	$	1	$	6	$	3	$	—	$	12
Ameren Illinois	—		2		—		2		—		—		4
Ameren	$	1	$	3	$	1	$	8	$	3	$	—	$	16
2012
Ameren Missouri	$	—	$	1	$	1	$	10	$	3	$	—	$	15
Ameren Illinois	—		—		—		—		—		—		—
Ameren	$	—	$	1	$	1	$	10	$	3	$	—	$	15

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of March 31, 2013, and December 31, 2012, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on March 31, 2013, or December 31, 2012, 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)
2013
Ameren Missouri	$	66	$	1	$	62
Ameren Illinois	121		31		78
Ameren	$	187	$	32	$	140
2012
Ameren Missouri	$	78	$	3	$	71
Ameren Illinois	148		58		84
Ameren	$	226	$	61	$	155

(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 determined after consideration of the effects of such agreements.

Derivatives that Qualify for Regulatory Deferral

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three months ended March 31, 2013, and 2012:

		Gain (Loss) Recognized in Regulatory  Liabilities or Regulatory Assets
		2013			2012
Ameren	Fuel oils	$	—		$	5
	Natural gas	36			(18		)
	Power(a)	20			(162		)
	Total	$	56		$	(175	)
Ameren Missouri	Fuel oils	$	—		$	5
	Natural gas	4			(2		)
	Power	(10		)	(1		)
	Total	$	(6	)	$	2
Ameren Illinois	Natural gas	$	32		$	(16	)
	Power	30			(144		)
	Total	$	62		$	(160	)

(a) Amounts include intercompany eliminations.

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NOTE 8 - 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, United States 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 United States 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. 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. 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.

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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 three months ended March 31, 2013:

		Fair Value								Weighted
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Average
Level 3 Derivative asset and liability - commodity contracts(a):
Ameren	Fuel oils	$	7	$	(2	)	Discounted cash flow	Escalation rate(%)(b)	.20 - .59	.39
								Counterparty credit risk(%)(c)(d)	.26 - 3	1
							Option model	Volatilities(%)(b)	10 - 19	17
	Natural gas	3		(1		)	Option model	Escalation rate(%)(b)	.20 - .46	.37
								Nodal basis($/mmbtu)(c)	(.24) - (.04)	(.19)
							Discounted cash flow	Escalation rate(%)(b)	.20 - .46	.35
								Nodal basis($/mmbtu)(c)	(.18) - 0	(.01)
								Counterparty credit risk(%)(c)(d)	.26 - 5	1
								Ameren credit risk(%)(c)(d)	2 - 3	3
	Power(e)	12		(91		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)	24 - 48	33
								Estimated auction price for FTRs($/MW)(b)	0 - 4,280	190
								Nodal basis($/MWh)(c)	(5) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	.22 - 5	2
								Ameren credit risk(%)(c)(d)	2 - 3	3
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	5 - 7	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)(d)	5 - 7	6
	Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	42 - 45	43
Ameren Missouri	Fuel oils	$	7	$	(2	)	Discounted cash flow	Escalation rate(%)(b)	.20 - .59	.39
								Counterparty credit risk(%)(c)(d)	.26 - 3	1
							Option model	Volatilities(%)(b)	10 - 19	17
	Natural gas	1		(1		)	Option model	Escalation rate(%)(b)	.20 - .46	.37
								Nodal basis($/mmbtu)(c)	(.24) - (.04)	(.19)
							Discounted cash flow	Escalation rate(%)(b)	.20 - .46	.26
								Nodal basis($/mmbtu)(c)	(.18) - (.02)	(.04)
								Counterparty credit risk(%)(c)(d)	.26 - 5	1
								Ameren Missouri credit risk(%)(c)(d)	2	(f)
	Power(e)	9		(7		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)	24 - 51	38
								Estimated auction price for FTRs($/MW)(b)	0 - 4,280	190
								Nodal basis($/MWh)(c)	(5) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	.22 - 5	1
								Ameren Missouri credit risk(%)(c)(d)	2	(f)
	Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	42 - 45	43
Ameren Illinois	Natural gas	$	2	$	—		Discounted cash flow	Escalation rate(%)(b)	.20 - .46	.33
								Nodal basis($/mmbtu)(c)	(.05) - 0	—
								Counterparty credit risk(%)(c)(d)	.70 - 2	1
								Ameren Illinois credit risk(%)(c)(d)	3	(f)
	Power(e)	3		(84		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(b)	24 - 42	32
								Nodal basis($/MWh)(b)	(4) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	2	(f)
								Ameren Illinois credit risk(%)(c)(d)	3	(f)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	5 - 7	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6

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

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

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

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

(e) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand.

(f) Not applicable.

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 twelve-month period ended December 31, 2012:

		Fair Value								Weighted
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Average
Level 3 Derivative asset and liability - commodity contracts(a):
Ameren	Fuel oils	$	8	$	(3	)	Discounted cash flow	Escalation rate(%)(b)	.21 - .60	.44
								Counterparty credit risk(%)(c)(d)	.12 - 1	1
								Ameren credit risk(%)(c)(d)	2	(e)
							Option model	Volatilities(%)(b)	7 - 27	24
	Power(f)	14		(114		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)	22 - 47	31
								Estimated auction price for FTRs($/MW)(b)	(281) - 1,851	178
								Nodal basis($/MWh)(c)	(5) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	.22 - 1	1
								Ameren credit risk(%)(c)(d)	2 - 5	5
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 8	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6
	Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	43 - 46	44
Ameren Missouri	Fuel oils	$	8	$	(3	)	Discounted cash flow	Escalation rate(%)(b)	.21 - .60	.44
								Counterparty credit risk(%)(c)(d)	.12 - 1	1
								Ameren Missouri credit risk(%)(c)(d)	2	(e)
							Option model	Volatilities(%)(b)	7 - 27	24
	Power(f)	14		(3		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)	24 - 56	36
								Estimated auction price for FTRs($/MW)(b)	(281) - 1,851	178
								Nodal basis($/MWh)(c)	(5) - (1)	(2)
								Counterparty credit risk(%)(c)(d)	.22 - 1	1
								Ameren Missouri credit risk(%)(c)(d)	2
	Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	43 - 46	44
Ameren Illinois	Power(f)	$	—	$	(111	)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(b)	22 - 47	30
								Nodal basis($/MWh)(b)	(5) - (1)	(3)
								Ameren Illinois credit risk(%)(c)(d)	5	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 8	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6

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

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

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

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

(e) Not applicable.

(f) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand.

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 no gains or losses in the first three months of 2013 or 2012 related to valuation adjustments for counterparty default risk. At March 31, 2013,

34

the counterparty default risk liability valuation adjustment related to derivative contracts totaled $1 million, less than $1 million, and $1 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. At December 31, 2012, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $7 million, less than $1 million, and $7 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively.

35

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of March 31, 2013:

		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	Derivative assets - commodity contracts(a):
	Fuel oils	$	3	$	—	$	7	$	10
	Natural gas	1		4		3		8
	Power	—		7		12		19
	Total derivative assets - commodity contracts	$	4	$	11	$	22	$	37
	Nuclear Decommissioning Trust Fund(b):
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	294		—		—		294
	Debt securities:
	Corporate bonds	—		48		—		48
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		77		—		77
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	296	$	138	$	—	$	434
	Total Ameren	$	300	$	149	$	22	$	471
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	3	$	—	$	7	$	10
	Natural gas	—		1		1		2
	Power	—		7		9		16
	Total derivative assets - commodity contracts	$	3	$	8	$	17	$	28
	Nuclear Decommissioning Trust Fund(b):
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	294		—		—		294
	Debt securities:
	Corporate bonds	—		48		—		48
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		77		—		77
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	296	$	138	$	—	$	434
	Total Ameren Missouri	$	299	$	146	$	17	$	462
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	1	$	3	$	2	$	6
	Power	—		—		3		3
	Total Ameren Illinois	$	1	$	3	$	5	$	9
Liabilities:
Ameren	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	1	$	—	$	2	$	3
	Natural gas	5		73		1		79
	Power	—		8		91		99
	Uranium	—		—		2		2
	Total Ameren	$	6	$	81	$	96	$	183
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	1	$	—	$	2	$	3
	Natural gas	5		6		1		12
	Power	—		8		7		15
	Uranium	—		—		2		2
	Total Ameren Missouri	$	6	$	14	$	12	$	32
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	67	$	—	$	67
	Power	—		—		84		84
	Total Ameren Illinois	$	—	$	67	$	84	$	151

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

(b) Balance excludes $3 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, 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	Derivative assets - commodity contracts(a):
	Fuel oils	$	4	$	—	$	8	$	12
	Natural gas	—		2		—		2
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	4	$	3	$	22	$	29
	Nuclear Decommissioning Trust Fund(b):
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	264		—		—		264
	Debt securities:
	Corporate bonds	—		47		—		47
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		81		—		81
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	265	$	141	$	—	$	406
	Total Ameren	$	269	$	144	$	22	$	435
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	4	$	—	$	8	$	12
	Natural gas	—		1		—		1
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	4	$	2	$	22	$	28
	Nuclear Decommissioning Trust Fund(b):
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	264		—		—		264
	Debt securities:
	Corporate bonds	—		47		—		47
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		81		—		81
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	265	$	141	$	—	$	406
	Total Ameren Missouri	$	269	$	143	$	22	$	434
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	—	$	1	$	—	$	1
	Power	—		—		—		—
	Total Ameren Illinois	$	—	$	1	$	—	$	1

37

		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	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	1	$	—	$	3	$	4
	Natural gas	7		102		—		109
	Power	—		1		114		115
	Uranium	—		—		2		2
	Total Ameren	$	8	$	103	$	119	$	230
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	1	$	—	$	3	$	4
	Natural gas	7		8		—		15
	Power	—		1		3		4
	Uranium	—		—		2		2
	Total Ameren Missouri	$	8	$	9	$	8	$	25
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	94	$	—	$	94
	Power	—		—		111		111
	Total Ameren Illinois	$	—	$	94	$	111	$	205

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

(b) Balance excludes $2 million of receivables, payables, and accrued income, net.

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The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2013:

		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2013	$	5		$	(a)		$	5
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—			(a)			—
Total realized and unrealized gains (losses)		—			(a)			—
Purchases		1			(a)			1
Sales		—			(a)			—
Settlements		(1	)		(a)			(1	)
Ending balance at March 31, 2013	$	5		$	(a)		$	5
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2013	$	—		$	(a)		$	—
Natural gas:
Beginning balance at January 1, 2013	$	—		$	—		$	—
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—			1			1
Total realized and unrealized gains (losses)		—			1			1
Purchases		—			1			1
Ending balance at March 31, 2013	$	—		$	2		$	2
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2013	$	—		$	—		$	—
Power:
Beginning balance at January 1, 2013	$	11		$	(111	)	$	(100	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		5			14			19
Total realized and unrealized gains (losses)		5			14			19
Settlements		(13	)		16			3
Transfers into Level 3		(2	)		—			(2	)
Transfers out of Level 3		1			—			1
Ending balance at March 31, 2013	$	2		$	(81	)	$	(79	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2013	$	(3	)	$	14		$	11
Uranium:
Beginning balance at January 1, 2013	$	(2	)	$	(a)		$	(2	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—			(a)			—
Total realized and unrealized gains (losses)		—			(a)			—
Ending balance at March 31, 2013	$	(2	)	$	(a)		$	(2	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2013	$	—		$	(a)		$	—

(a) Not applicable.

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The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2012:

		Net derivative commodity contracts
		Ameren Missouri				Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2012	$	3			$	(a)		$	3
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		2				(a)			2
Total realized and unrealized gains (losses)		2				(a)			2
Transfers into Level 3		2				(a)			2
Ending balance at March 31, 2012	$	7			$	(a)		$	7
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012	$	2			$	(a)		$	2
Natural gas:
Beginning balance at January 1, 2012	$	(14		)	$	(160	)	$	(174		)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(2		)		(26	)		(28		)
Total realized and unrealized gains (losses)		(2		)		(26	)		(28		)
Settlements		1				16			17
Transfers out of Level 3		15				170			185
Ending balance at March 31, 2012	$	—			$	—		$	—
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012	$	—			$	—		$	—
Power(b):
Beginning balance at January 1, 2012	$	21			$	(140	)	$	81
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		13				(220	)		(158		)
Total realized and unrealized gains (losses)		13				(220	)		(158		)
Settlements		(13		)		76			(4		)
Transfers out of Level 3		(1		)		—			(1		)
Ending balance at March 31, 2012	$	20			$	(284	)	$	(82		)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012	$	10			$	(202	)	(c) $	(156		)
Uranium:
Beginning balance at January 1, 2012		$	(1	)		(a)			$	(1	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—				(a)			—
Total realized and unrealized gains (losses)		—				(a)			—
Ending balance at March 31, 2012		$	(1	)		(a)			$	(1	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012		$	—			(a)			$	—

(a) Not applicable.

(b) Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company.

(c) 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.

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 March 31, 2013, and the previous reporting period ended December 31, 2012. 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 months ended March 31, 2013, and 2012, 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 months ended March 31, 2013, and 2012:

40

	2013			2012
Ameren - 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	—			185
Transfers into Level 3 / Transfers out of Level 2 - Power	(2		)	—
Transfers out of Level 3 / Transfers into Level 2 - Power	1			(1		)
Net fair value of Level 3 transfers	$	(1	)	$	186
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	(2		)	—
Transfers out of Level 3 / Transfers into Level 2 - Power	1			(1		)
Net fair value of Level 3 transfers	$	(1	)	$	16
Ameren Illinois - derivative commodity contracts:
Transfers out of Level 3 / Transfers into Level 2 - Natural gas	$	—		$	170

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. Ameren’s and Ameren Missouri’s carrying amounts of investments in debt securities related to the two CTs from the city of Bowling Green and Audrain County approximate fair value. These investments are classified as held-to-maturity. These investments are considered Level 2 in the fair value hierarchy as they are valued based on similar market transactions. Short-term borrowings for Ameren Missouri and Ameren Illinois 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 March 31, 2013, and December 31, 2012:

	March 31, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:(a)(b)
Long-term debt and capital lease obligations (including current portion)	$	6,158	$	7,127	$	6,157	$	7,110
Preferred stock	142		124		142		123
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	4,006	$	4,645	$	4,006	$	4,625
Preferred stock	80		74		80		73
Ameren Illinois:
Long-term debt (including current portion)	$	1,727	$	2,027	$	1,727	$	2,020
Preferred stock	62		50		62		49

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

(b) Preferred stock along with the noncontrolling interest of EEI is recorded in “Noncontrolling Interests” on the balance sheet.

NOTE 9 - RELATED PARTY TRANSACTIONS

Ameren and its subsidiaries 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 which gave Genco the option to sell to AERG all, but not less than all, of the Elgin, Gibson City, and Grand Tower gas-fired energy centers. The put option agreement required AERG to secure and maintain an Ameren guarantee of payment of contingent obligations under the agreement. Ameren provided such a guarantee on March 28, 2012.

On March 14, 2013, the put option agreement was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley. The guarantee provided by Ameren was also modified to replace references to AERG with references to Medina Valley. The guarantee will remain in effect until either Medina Valley or

41

Ameren satisfies all of the payment obligations under the put option agreement, or until the put option agreement is terminated and no further payments are owed by Medina Valley to Genco. On March 14, 2013, Genco exercised the option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

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, 2012, and March 31, 2013, 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, beginning in June 2012, 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. Marketing Company sells and Ameren Illinois purchases 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 March 31, 2013, Ameren Illinois’ payable to Marketing Company for the purchase of trade receivables totaled $9 million. During the three months ended March 31, 2013, Ameren Illinois purchased $33 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 Ameren’s consolidated financial statements. After the New AER divestiture is complete, these transactions will no longer be eliminated in Ameren’s consolidated financial statements.

Parent Company Guarantees

In the ordinary course of business, Ameren (parent) enters into various agreements providing financial assurance to third parties on behalf of its subsidiaries. Such agreements include, for example, guarantees and letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit and reducing

the amount of cash collateral required to be posted. These agreements guarantee performance by Ameren's subsidiaries of obligations already existing on Ameren's consolidated balance sheet.

Upon the divestiture of New AER, subject to certain exceptions, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture and provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. IPH shall indemnify Ameren for any payments it makes pursuant to these credit support obligations. IPH's indemnification obligation will be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH's indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions). See Note 2 - Divestiture Transactions and Discontinued Operations.

At March 31, 2013, Ameren had a total of $269 million in guarantees outstanding, which included:

• $158 million related to Ameren's Merchant Generation segment, primarily for Marketing Company as support for physically and financially settled power transactions with its counterparties. As of March 31, 2013, this amount does not represent an incremental consolidated Ameren obligation; rather, it represents Ameren parental guarantees of subsidiary obligations to third parties, which may include affiliates, in order to allow the subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Ameren's estimated exposure for obligations under transactions covered by these guarantees was $26 million at March 31, 2013, which represents the total amount Ameren (parent) could be required to fund based on March 31, 2013, market prices.

• $33 million associated with the guarantee provided by Ameren for Medina Valley on March 14, 2013, relating to the amended put option agreement between Genco and Medina Valley. Genco exercised the put option in March 2013 and received an initial payment of $100 million. Genco advanced the initial payment amount it received into the non-state-regulated subsidiaries money pool.

• $65 million provided to two clearing brokers acting as futures commission merchants for the clearing of certain power, natural gas, and fuels commodity transactions for AER. As of March 31, 2013, AER was transitioning from its existing futures commission merchant to a new futures commission merchant. As of May 1, 2013, following completion of this transition, only one guarantee for $25 million is required.

• $13 million related to requirements for asset transactions, leasing, and other service agreements. At March 31, 2013, Ameren estimated it had no exposure to any of these guarantees.

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Additionally, at March 31, 2013, Ameren had issued letters of credit totaling $37 million as credit support to certain subsidiaries.

Money Pools

See Note 4 - Short-term Debt and Liquidity for a discussion of affiliate borrowing arrangements.

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three months ended March 31, 2013, and 2012. 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 4 - Short-term Debt and Liquidity of this report.

			Three Months ended March 31
Agreement	Income Statement Line Item		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2013	$	1	$ (a)
agreements with Ameren Illinois		2012	(b)		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2013	5		(b)
rent and facility services		2012	5		(b)
Ameren Missouri and Genco gas	Operating Revenues	2013	(b)		(a)
transportation agreement		2012	(b)		(a)
Transmission services agreement	Operating Revenues	2013	(a)		6
with Marketing Company		2012	(a)		2
Total Operating Revenues		2013	$	6	$	6
		2012	5		2
Ameren Illinois power supply	Purchased Power	2013	$ (a)		$	26
agreements with Marketing Company		2012	(a)		87
Ameren Illinois power supply	Purchased Power	2013	(a)		1
agreements with Ameren Missouri		2012	(a)		(b)
Total Purchased Power		2013	$ (a)		$	27
		2012	(a)		87
Ameren Services support services	Other Operations and Maintenance	2013	$	31	$	25
agreement		2012	28		23
Insurance premiums(c)	Other Operations and Maintenance	2013	(b)		(a)
		2012	(b)		(a)
Total Other Operations and		2013	$	31	$	25
Maintenance Expenses		2012	28		23
Money pool borrowings (advances)	Interest Charges	2013	$ (b)		$ (b)
		2012	—		(b)

(a) Not applicable.

(b) Amount less than $1 million.

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

NOTE 10 - 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 in this report and in our Form 10-K, 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 - Divestiture Transactions and Discontinued Operations, Note 3 - Rate and Regulatory Matters, Note 9 - Related Party Transactions and Note 11 - Callaway Energy Center in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at March 31, 2013. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.

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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
Missouri 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) First layer of coverage provides for $500 million in property damage, decontamination, premature decommissioning, and the second layer of coverage provides excess property insurance up to $2.25 billion for losses in excess of the $500 million primary coverage. Effective April 1, 2013, a $1.5 billion sub-limit was established for non-nuclear events.

(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. Effective April 1, 2013, non-nuclear events are sub-limited to $327.6 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 up to $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 9 - 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. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

At March 31, 2013, total other obligations related to the procurement of coal, natural gas, nuclear fuel, purchased power, methane gas, and equipment and meter reading services, among other agreements, at Ameren, Ameren Missouri and Ameren Illinois were $7,515 million, $5,151 million, and $2,316 million, respectively. Total unrecognized tax benefits at March 31, 2013, which were not included in the previous totals, for Ameren, Ameren Missouri and Ameren Illinois were $190 million, $126 million, and $4 million, respectively.

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.

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In addition to existing laws and regulations, including the Illinois MPS that applies to AER's coal-fired energy centers in Illinois, the EPA is developing 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 AER, 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 fine particulates, SO_2, and NO_x emissions; the CSAPR, which would have required further reductions of SO₂ emissions and NO_x emissions from energy centers; a regulation governing management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from energy centers; revised NSPS for particulate matter, SO₂, and NO_x emissions from new sources; new effluent standards applicable to discharges from steam-electric generating units; 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 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 AER. Compliance with these 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 tables 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 and the MATS as of March 31, 2013. In addition, the estimates assume that CCR will continue to be regarded as nonhazardous. The estimates do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures or the impact of the effluent standards applicable to steam-electric generating units that the EPA proposed in April 2013 as our evaluation of those impacts is ongoing. The estimates shown in the tables below could change significantly depending upon a variety of factors including:

• Ameren’s exit from the Merchant Generation business;

• 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 or new rules governing air pollutant transport;

• regulations under the Clean Water Act regarding cooling water intake structures or effluent standards;

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

• new limitations or standards under the Clean Water Act applicable to discharges from steam-electric generating units;

• new technology;

• expected power prices;

• variations in costs of material or labor; and

• alternative compliance strategies or investment decisions.

Continuing Operations:

	2013		2014 - 2017					2018 - 2022					Total
AMO(a)	$	105	$	215	-	$	260	$	795	-	$	975	$	1,115	-	$	1,340

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

Discontinued Operations:

	2013		2014 - 2017					2018 - 2022					Total
Genco(a)	30		100		-	125		220		-	270		350		-	425
AERG	5		20		-	25		20		-	25		45		-	55
Total(b)	$	35	$	120	-	$	150	$	240	-	$	295	$	395	-	$	480

(a) Includes estimated costs of approximately $20 million annually, excluding capitalized interest, from 2013 through 2017 for construction of two Newton energy center scrubbers.

(b) Assumes the Merchant Generation facilities are owned by Ameren.

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 SO₂ and NO_x emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO₂ and NO_x emissions (the CAIR). The CAIR 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 SO₂ emissions, annual NO_x emissions, and ozone season NO_x emissions.

In December 2008, the United States Court of Appeals for the District of Columbia Circuit 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. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR. In August 2012, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that vacated the CSAPR in its entirety, finding that the EPA exceeded

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its authority in imposing the CSAPR's emission limits on states. In January 2013, the full Court of Appeals for the District of Columbia Circuit denied the EPA's request for rehearing. In March 2013, the EPA and certain environmental groups filed an appeal of the Circuit Court’s remand of CSAPR to the Supreme Court. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the decision to vacate the CSAPR is overturned by the United States Supreme Court.

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 in certain cases, emission compliance can be achieved by averaging emissions from similar electric generating units at the same 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 extensions to comply with the MATS by April 2016.

Separately, in December 2012, the EPA issued a final rule that made the national ambient air quality standard for fine particulate matter more stringent. States must develop control measures designed to reduce the emission of fine particulate matter below required levels to achieve compliance with the new standard. Such measures may or may not apply to energy centers but could require reductions in SO₂ and NO_x emissions. Compliance with the rule is required by 2020, or 2025 if an extension of time to achieve compliance is granted. Ameren Missouri and AER are currently evaluating the new standard while the states of Missouri and Illinois develop their attainment plans.

In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standards for ozone. The EPA is required to revisit these standards for ozones again in 2013. The states of Illinois and Missouri will be required to develop attainment plans to comply with the 2008 ambient air quality standards for ozone, which could result in additional emission control requirements for power plants by 2020. Ameren, Ameren Missouri and AER 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.

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 described below. The Illinois Pollution Control Board approved AER's proposed plan to restrict its SO₂ emissions through 2014 to levels lower than those previously required by the 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, or Ameren’s ability after the divestiture of New AER occurs, 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.

As a condition to IPH’s obligation to complete the acquisition of New AER, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS. AER and Dynegy filed a transfer request with the Illinois Pollution Control Board on May 2, 2013. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of AER.

Under the MPS, AER is required to reduce mercury, NO_x and SO₂ emissions with declining limits starting in 2009 for mercury and in 2010 for NO_x and SO_2..The final NO_x limit became effective in 2012. The final mercury limit will become effective in 2015 and the final SO₂ limit will become effective 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 installations and other pollution controls at some of AER's energy centers. To comply with the MPS and other air emissions laws and regulations, AER is installing equipment designed to reduce its emissions of mercury, NO_x, and SO₂. AER has installed three scrubbers at two energy centers. Two additional scrubbers are being constructed at the Newton energy center. AER will continue to review and adjust its compliance plans in light of evolving outlooks for power and capacity prices,

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delivered fuel costs, emission standards required under environmental laws and regulations, and compliance technologies, among other factors.

Environmental compliance costs could be prohibitive at some of Ameren's, Ameren Missouri's and AER'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 SO₂ emissions and created annual and ozone season NO_x allowances. Ameren and Ameren Missouri expect to have adequate CAIR allowances for 2013 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 rates for electricity and thereby household costs. 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 regulations could cause the conversion of coal-fired power plants to natural gas, or the construction of new natural gas plants to replace coal-fired power plants. As a result, economy wide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas.

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 issued 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 address 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 Circuit upheld the Tailoring Rule. Industry groups and a coalition of states filed petitions in April 2013 requesting that the United States Supreme Court review the circuit court’s decision upholding the Tailoring Rule.

Separately, in March 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 therefore does not affect any of the Ameren, Ameren Missouri or AER 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 2013. 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.

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 AER, as well as other similarly situated electric power generators, to close some coal-fired facilities earlier than planned, which could lead to possible

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impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren's and Ameren Missouri'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 that CO₂ emissions from several industrial companies, including Ameren Missouri, Genco, and AERG, created 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, their impact on our coal-fired energy centers and our customers' costs is unknown, but they 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 DistrictCourt 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 the requirement to install 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 and Ameren Missouri. 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.

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% 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 a specified level. The proposed rule also requires existing power 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 AER 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 AER 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 April 2013, the EPA announced its proposal to revise the effluent limitation guidelines applicable to steam electric generating units under the Clean Water Act. Effluent limitation guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The proposed revision targets wastewater streams associated with fluegas desulfurization (i.e. scrubbers),

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fly ash, bottom ash, fluegas mercury control, CCR leachate from landfills and impoundments, nonchemical metal cleaning and gassification of fuels. The EPA’s proposal identifies several alternatives for addressing these waste streams, including best management practices for CCR impoundments.The EPA’s proposed rule raised several compliance options that would prohibit effluent discharges of certain, but not all, waste streams and impose more stringent limitations on certain components in wastewater discharges from power plants. If enacted as proposed, Ameren Missouri and AER would be subject to the revised limitations beginning July 1, 2017, but no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impact on our operations if enacted as proposed. The EPA expects to finalize the rule in 2014.

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.

As part of the transfer of generation assets by our rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003, Ameren Illinois’ predecessor companies contractually agreed to indemnify Genco and AERG for claims relating to pre-existing environmental conditions at the transferred sites. The plant transfer agreements between both Genco and Ameren Illinois and AERG and Ameren Illinois will be amended as part of the transaction agreement for Ameren to divest New AER to IPH. The agreements will specify that all environmental liabilities associated with the Meredosia and Hutsonville energy centers will be assumed by Medina Valley. The agreements will also specify that all environmental liabilities associated with Genco’s Newton and Coffeen energy centers and AERG’s E.D. Edwards and Duck Creek energy centers will no longer be indemnified by Ameren Illinois. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of New AER.

As of March 31, 2013, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois. These are in various stages of investigation, evaluation, remediation and closure. Based on current estimated plans, Ameren Illinois could substantially conclude remediation efforts at most of these sites by 2018. 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 March 31, 2013, Ameren Missouri has one remaining former MGP site for which remediation is scheduled. Remediation is complete at the other Ameren Missouri former

MGP sites. Ameren Missouri does not currently have a rate rider mechanism that permits it to recover from utility customers remediation costs associated with MGP sites from utility customers.

The following table presents, as of March 31, 2013, the estimated probable obligation to remediate these former MGP sites.

	Estimate				Recorded   Liability(a)
	Low		High
Ameren	$	259	$	342	$	259
Ameren Missouri	5		6		5
Ameren Illinois	254		336		254

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

The scope and extent to which these former MGP sites are remediated may increase as remediation efforts continue. Considerable uncertainty remains in these estimates as many factors can influence the ultimate actual costs, including site specific unanticipated underground structures, the degree to which groundwater is encountered, regulatory changes, local ordinances and site accessibility. The actual costs may vary substantially from these estimates.

Ameren Illinois utilized an off-site landfill, which Ameren Illinois did not own, in connection with its operation of the Coffeen energy center prior to the formation of Genco. While not currently mandated, Ameren Illinois may be required to perform certain remediation activities associated with that landfill. As of March 31, 2013, Ameren Illinois estimated the obligation related to the cleanup 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 March 31, 2013, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.

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 March 31, 2013, 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

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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 that this trust fund will be sufficient to complete the remaining adjacent off-site cleanup and it therefore has no recorded liability at March 31, 2013, for this site.

Ameren Missouri also has a federal agency mandate to complete an 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 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 2013. 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 Sauget Area 2. As of March 31, 2013, Ameren Missouri estimated its obligation related to Sauget Area 2 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.

In December 2012, Ameren Missouri signed an administrative order with the EPA and agreed to investigate soil and groundwater conditions at an Ameren Missouri owned substation in St. Charles, Missouri. As of March 31, 2013, Ameren Missouri estimated the obligation related to the cleanup at $1.7 million to $4.5 million. Ameren Missouri recorded a liability of $1.7 million to represent its estimated minimum obligation for this site, 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 laws. We are unable to determine whether such practices will result in future environmental commitments or will 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. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric generating units would apply to ash pond and CCR management and intended to align this proposal with the CCR rules proposed in May 2010. 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 AER 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 AER 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.

The Illinois EPA has issued violation notices with respect to groundwater conditions existing at Genco’s ash pond systems. In April 2013, AER filed a proposed rulemaking with the Illinois Pollution Control Board which, if approved, would provide for the systematic and eventual closure of ash ponds. The rulemaking process could take up to two years to complete. Genco and AERG changed their ARO fair value estimates relating to their ash ponds to revise their expected retirement dates.

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 March 31, 2013, Ameren Missouri had an insurance receivable balance of $68 million. Ameren Missouri's results of operations, financial position and liquidity could be adversely affected if its remaining liability insurance claims are not paid by insurers.

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 that the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting 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 appealed the January

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2011 ruling to the United States Court of Appeals for the Eighth Circuit. 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 second insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the April 2012 litigation, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In an April 2013 ruling, the United States Court of Appeals for the Eighth Circuit affirmed the denial by the United States District Court for the Eastern District of Missouri of the insurer's motion to require arbitration.

Asbestos-related Litigation

Ameren, Ameren Missouri, and Ameren Illinois 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 the average number of parties being 80 as of March 31, 2013. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.

The claims filed against Ameren, Ameren Missouri and Ameren Illinois allege injury from asbestos exposure during the plaintiffs' activities at our present or former energy centers.

Former CIPS energy centers are now owned by Genco, and former CILCO energy centers are now owned by AERG. As a condition to transferring ownership of the CIPS and CILCO energy centers, CIPS and CILCO, now Ameren Illinois, contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising or existing from activities prior to the transfer. The plant transfer agreement between Genco and Ameren Illinois and the plant transfer agreement between AERG and Ameren Illinois each will be amended pursuant to the transaction agreement in which Ameren agrees to divest New AER to IPH. The amended plant transfer agreements will provide that Ameren Illinois will continue to retain asbestos exposure related liabilities for claims arising or existing from activities prior to the transfer of the ownership of the CIPS and CILCO energy centers to Genco and AERG. IPH will be responsible for any asbestos-related claims arising from activities that occur after it takes ownership of New AER. Any asbestos-related claims arising solely from activities post transfer of the energy centers from CIPS and CILCO to Genco and AERG, respectively, but prior to IPH taking ownership of New AER, of which there are currently none, will be retained by Ameren.See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren's divestiture of AER.

The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of March 31, 2013:

Ameren	Ameren Missouri	Ameren Illinois	Total(a)
3	66	81	103

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

At March 31, 2013, Ameren, Ameren Missouri and Ameren Illinois had liabilities of $19 million, $8 million, and $11 million, respectively, recorded to represent their best estimate of their obligations related to asbestos claims.

Ameren Illinois has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are to be recovered from a trust fund that was established when Ameren acquired IP. At March 31, 2013, 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. Following the Ameren Illinois Merger, this rider is applicable only for claims that occurred within IP’s historical service territory. Similarly, the rider will permit recovery only from customers within IP’s historical service territory.

Ameren Illinois Municipal Taxes

Ameren Illinois received tax liability notices from the city of O'Fallon, Illinois relating to prior-period electric and natural gas municipal taxes. The city alleges that Ameren Illinois failed to collect prior-period taxes from more than 2,100 local resident addresses primarily innewly annexed areas for the period 2005 through 2010. Ameren Illinois is challenging the city's position on this matter. Ameren Illinois believes its defenses to the notices of tax liability are meritorious and will defend itself vigorously. As of March 31, 2013, Ameren Illinois did not believe it was probable that the city of O'Fallon would prevail and therefore has not recorded a charge to earnings for a loss contingency related to this matter.  Should Ameren Illinois ultimately be found liable for these prior-period municipal taxes, the amount is estimated between $2 million and $4 million, including interest and penalties. In addition, at the end of 2012, the city of O'Fallon and six other cities issued tax liability notices alleging that Ameren Illinois failed to collect prior-period taxes from certain local resident addresses. At this time, it is premature in Ameren Illinois' review of the additional notices received at the end of 2012 to reasonably estimate any likelihood of loss.

Illinois Sales and Use Tax Exemptions and Credits

In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear 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

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their generation operations. The primary basis for those claims is that the determination in the Exelon casethat electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. In November 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 does not believe that it is probable that the state of Illinois will prevail and therefore has not recorded a charge to earnings for the loss contingency. From the second quarter of 2010 through December 31, 2011, Ameren claimed manufacturing exemptions and credits of $27 million, which represents the maximum potential tax liability to Ameren, excluding any penalties assessed or interest accrued.

Genco, including EEI, and AERG did not claim any additional manufacturing exemptions or credits in 2012 and do not anticipate claiming any additional manufacturing exemptions or credits in 2013, pending discussions with the Illinois Department of Revenue. Each company, however, is reserving the right to apply for applicable refunds at a later date.

Ameren will retain responsibility for this contingent liability after the divestiture of New AER is completed.

Medina Valley Asset Sale

In February 2012, Ameren completed the sale of the Medina Valley energy center’s net property and plant for cash proceeds of $16 million and an additional $1 million to be paid at the two-year anniversary date of the sale if all terms of the sale agreement were met. Ameren recognized a $10 million pretax gain 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. During the first quarter of 2013, Ameren concluded it was no longer probable it will receive the additional $1 million associated with this sale and therefore expensed the receivable amount.

NOTE 11 - 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 energy centers. Under the NWPA, Ameren and other companies that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established the fee that these companies pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatthour 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 companies 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 standard contract, Ameren Missouri collects one

mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway energy center.

Both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, however, no federal storage facility currently exists. 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 federal government 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 companies’ 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.

In January 2013, the DOE issued its plan for the management and disposal of spent nuclear fuel in response to the recommendation contained in the advisory commission's report. The DOE's plan calls for a pilot interim storage facility to begin operation with an initial focus on accepting spent nuclear fuel from shutdown reactor sites by 2021. By 2025, a larger interim storage facility would be available and would be co-located with the pilot facility. The plan also proposes to site a permanent geological repository to begin operation by 2048. 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 spent nuclear fuel from nuclear energy centers and fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners have sued the DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed a breach of contract lawsuit to recover costs that it incurred through 2009. This amount included the cost of reracking the Callaway energy center’s spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes that Ameren Missouri would not have incurred had DOE performed its contractual obligations. In June 2011, the parties reached a settlement that included an annual reimbursement of Ameren Missouri’s spent fuel storage and related costs through at least 2013. In March 2013, Ameren Missouri submitted its 2012 costs to the DOE for reimbursement under the settlement agreement. Ameren Missouri expects to receive the 2012 cost reimbursement of $6 million during the third quarter of 2013.

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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 deadline by which the NRC must act on this application. Among the rules that the NRC has historically relied upon in 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 energy center 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 2016.

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 2012, 2011, and 2010. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway energy center. Electric rates may be adjusted at such times to reflect changed estimates. If Ameren Missouri's operating license extension application is approved by the NRC, a revised funding analysis will be prepared and the rates charged to customers will be adjusted accordingly to reflect the operating license extension at the time of the next triennial cost study and funding analysis is approved by the MoPSC. 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 sheets. 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 3 - Rate and Regulatory Matters for additional information related to the Callaway energy center.

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 March 31, 2013, its estimated investment performance through March 31, 2013, and its pension funding policy, Ameren expects to make annual contributions of $60 million to $150 million in each of the next five years, with aggregate estimated contributions of $550 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’s 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 months ended March 31, 2013, and 2012:

	Pension Benefits						Postretirement Benefits
	Three Months						Three Months
	2013			2012			2013			2012
Service cost	$	24		$	21		$	6		$	6
Interest cost	40			42			12			13
Expected return on plan assets	(54		)	(52		)	(16		)	(14		)
Amortization of:
Prior service cost (benefit)	(1		)	(1		)	(1		)	(1		)
Actuarial loss	22			19			2			3
Net periodic benefit cost	$	31		$	29		$	3		$	7

Ameren Missouri and Ameren Illinois are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three months ended March 31, 2013, and 2012:

	Pension Costs				Postretirement Costs
	Three Months				Three Months
	2013		2012		2013		2012
Ameren Missouri	$	18	$	16	$	2	$	5
Ameren Illinois	10		10		1		2
Other	3		3		—		—
Ameren(a)	$	31	$	29	$	3	$	7

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

NOTE 13 - SEGMENT INFORMATION

Ameren historically had three reportable segments: Ameren Missouri, Ameren Illinois, and Merchant Generation. The Ameren Missouri segment for both 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 both 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 consisted primarily of the operations or activities of AER, including Genco, EEI, AERG, and Marketing Company. Ameren is divesting its Merchant Generation segment and therefore has excluded that segment’s information below. See Note 2 - Divestiture Transactions and Discontinued Operations for information regarding the Merchant Generation segment. The category called Other primarily includes Ameren parent company activities, Ameren Services, and ATXI. The Other category also includes activities previously included in the Merchant Generation segment that will be retained by Ameren after the divestiture of New AER and the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers is complete. See Note 2 - Divestiture Transactions and Discontinued Operations for information regarding the assets and liabilities retained by Ameren after the divestitures.

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The following table presents information about the revenues and specified items included in Ameren’s net income for the three months ended March 31, 2013, and 2012, and total assets as of March 31, 2013, and December 31, 2012.

Three Months	Ameren Missouri		Ameren Illinois		Other			Intersegment Eliminations			Consolidated
2013
External revenues	$	789	$	684	$	2		$	—		$	1,475
Intersegment revenues	7		—		2			(9		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	40		31		(17		)	—			54
2012
External revenues	$	686	$	724	$	2		$	—		$	1,412
Intersegment revenues	5		—		1			(6		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	21		27		(11		)	—			37
As of March 31, 2013:
Total assets	$	12,867	$	7,288	$	1,289		$	(992	)	$	20,452	(a)
As of December 31, 2012:
Total assets	$	13,043	$	7,282	$	1,228		$	(944	)	$	20,609	(a)

(a)    Excludes “Current assets of discontinued operations.” See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

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 its equity interests in 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, and, through

Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes.

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

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Immediately prior to Ameren’s entry into the transaction agreement with IPH, on March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. Ameren has commenced a sale process for these three gas-fired energy centers and expects a third-party sale to be completed during 2013. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding these divestitures. As a result of the transaction agreement with IPH and Ameren’s plan to sell its Elgin, Gibson City, and Grand Tower gas-fired energy centers, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation. Therefore, Ameren has segregated New AER’s and the Elgin, Gibson City, and Grand Tower gas-fired energy centers’ operating results, assets, and liabilities and presented them separately as discontinued operations for all periods presented in this report. Unless otherwise noted, the following sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations have been revised to exclude discontinued operations for all periods presented. See Note 2 - Divestiture Transactions and Discontinued Operations under Part I, Item 1 for additional information regarding that presentation.

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

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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.

OVERVIEW

Ameren reported a net loss attributable to Ameren Corporation of $145 million for the first quarter of 2013, compared with a net loss attributable to Ameren Corporation of $403 million for the first quarter of 2012. Net income attributable to Ameren Corporation from continuing operations increased to $54 million in the first quarter of 2013, from $37 million in the first quarter of 2012. The increase in first quarter 2013 earnings, compared to first quarter 2012, reflected improved earnings from Ameren Missouri and Ameren Illinois. Colder winter temperatures, which drove higher electric and natural gas sales volumes; new rates for Ameren Missouri electric and Ameren Illinois transmission service, both effective in January 2013; and the absence in 2013 of a required donation associated with the implementation of formula rates in Illinois, all benefited 2013 earnings comparisons. These favorable factors were partially offset by a reduction in Ameren Illinois electric delivery service revenues as a result of variation in the timing and amount of expected full-year recoverable costs under formula ratemaking and by higher Ameren Missouri non-fuel operations and maintenance expenses.

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 and simultaneously 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 are focused on minimizing the gap between allowed and earned returns on equity.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Immediately prior to Ameren’s entry into the transaction agreement with IPH, on March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. Ameren has commenced a sale process for these three gas-fired energy centers and expects a third-party sale to be completed during 2013. These divestitures will position Ameren to focus exclusively on its rate-regulated electric, natural gas and transmission operations, clarifying Ameren's strategic direction. Ameren intends to allocate its capital resources to those business opportunities which offer the most attractive risk-adjusted return potential.

In January 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service by

$50 million. In an attempt to reduce regulatory lag, Ameren Illinois used a future test year, 2014, in this proceeding. A decision in this proceeding is required by December 2013.

On March 14, 2013, the Illinois General Assembly passed legislation, which, if enacted, would result in certain amendments to the IEIMA that would modify its implementation. The passed legislation, Senate Bill 9, clarifies the provisions in the IEIMA that require the year-end rate base be used to calculate the revenue requirement reconciliation and that the interest applied to the revenue requirement reconciliation and return on equity collar adjustments would be consistent with the company's weighted average return calculated under the formula rate. Additionally, the legislation specifies the use of year-end capital structure for both the revenue requirement and the revenue requirement reconciliation. On May 5, 2013, the Illinois Governor vetoed this legislation. If this legislation is ultimately enacted through a legislative override in 2013, Ameren Illinois will submit revisions to its April 19, 2013 update filing based on the new law.

Ameren continues its plans to invest in electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The first project, Illinois Rivers, involves the building of 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 and right-of-way acquisitions are scheduled to commence in late 2013 after receipt of a certificate of public convenience and necessity, which ATXI requested from the ICC in November 2012. Construction is expected to begin in 2014. 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 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 through 2019. FERC has approved transmission rate incentives for the three MISO-approved projects. Separate from the ATXI projects discussed above, Ameren Illinois expects to invest approximately $1 billion in electric transmission assets over the next five years to address load growth and reliability requirements.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. The vast majority of Ameren's revenues are subject to state or federal regulation. This regulation has a material impact on the price we charge for our services. 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

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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 580 basis points. 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

The net loss attributable to Ameren Corporation decreased to $145 million, or a loss of $0.60 per share, in the first quarter of 2013, from $403 million, or a loss of $1.66 per share, in the first quarter of 2012. Net income attributable to Ameren Corporation from continuing operations increased to $54 million, or $0.22 per share, in the first quarter of 2013, from $37 million, or $0.15 per share, in the first quarter of 2012. Net income attributable to Ameren Corporation increased in the first quarter of 2013 in the Ameren Missouri segment and in the Ameren Illinois segment by

$19 million and $4 million, respectively, from the prior-year period.

Net income from continuing operations was favorably impacted in the first quarter of 2013, compared with the same period in 2012, by:

• the impact of colder winter weather conditions on electric and gas demand (estimated at 10 cents per share);

• increased transmission rates at Ameren Illinois (3 cents per share); and

• higher utility rates at Ameren Missouri pursuant to an order issued by the MoPSC, which became effective in January 2013, partially offset by increased regulatory asset amortization directed by the rate order (2 cents per share).

Net income from continuing operations was negatively impacted in the first quarter of 2013, compared with the same period in 2012, by a decrease in Ameren Illinois' electric earnings driven by a reduction in electric delivery services revenues as a result of the variation in the timing and amount of expected full-year recoverable costs under formula ratemaking, partially offset by lower required donations pursuant to the IEIMA (6 cents per share).

The cents per share information presented above is based on average shares outstanding in the first quarter of 2012. For further details regarding the Ameren Companies' results of operations for the first quarter of 2013, including explanations of Margins, Other Operations and Maintenance Expenses, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income and Expenses, Interest Charges, Income Taxes, and Loss from Discontinued Operations, Net of Tax, see the major headings below.

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Below is a table of income statement components by segment for the three months ended March 31, 2013, and 2012:

	Ameren Missouri			Ameren Illinois			Other / Intersegment Eliminations			Total
Three Months 2013:
Electric margin	$	493		$	233		$	(2	)	724
Natural gas margin	27			131			(1		)	157
Other operations and maintenance	(221		)	(176		)	(2		)	(399		)
Depreciation and amortization	(111		)	(61		)	(3		)	(175		)
Taxes other than income taxes	(77		)	(42		)	(3		)	(122		)
Other income and (expenses)	9			(2		)	—			7
Interest charges	(60		)	(31		)	(10		)	(101		)
Income (taxes) benefit	(19		)	(20		)	4			(35		)
Income (loss) from continuing operations	41			32			(17		)	56
Loss from discontinued operations, net of tax	—			—			(199		)	(199		)
Net income (loss)	41			32			(216		)	(143		)
Noncontrolling interest and preferred dividends	(1		)	(1		)	—			(2		)
Net income (loss) attributable to Ameren Corporation	$	40		$	31		$	(216	)	(145		)
Three Months 2012:
Electric margin	$	436		$	241		$	(3	)	$	674
Natural gas margin	23			110			—			133
Other operations and maintenance	(202		)	(168		)	1			(369		)
Depreciation and amortization	(108		)	(55		)	(4		)	(167		)
Taxes other than income taxes	(71		)	(39		)	(3		)	(113		)
Other income and (expenses)	12			(10		)	—			2
Interest charges	(56		)	(33		)	(9		)	(98		)
Income (taxes) benefit	(12		)	(18		)	7			(23		)
Income (loss) from continuing operations	22			28			(11		)	39
Loss from discontinued operations, net of tax	—			—			(442		)	(442		)
Net income (loss)	22			28			(453		)	(403		)
Noncontrolling interest and preferred dividends	(1		)	(1		)	2			—
Net income (loss) attributable to Ameren Corporation	$	21		$	27		$	(451	)	$	(403	)

Margins

The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in the three months ended March 31, 2013, compared with the same period in 2012. 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.

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Three Months	Ameren Missouri			Ameren Illinois			Other(a)			Ameren
Electric revenue change:
Effect of weather (estimate)(b)	$	31		$	5		$	—		$	36
Regulated rates:
Base rates (estimate)	35			(16		)	—			19
Recovery of FAC under-recovery(c)	18			—			—			18
Off-system (reduction in base rates)	(19		)	—			(1		)	(20		)
MEEIA (energy efficiency)	7			—			—			7
Transmission services	2			9			1			12
Gross receipts tax	5			—			—			5
Illinois pass-through power supply costs	—			(63		)	—			(63		)
Rate-regulated sales volume (excluding the impact of abnormal weather)	13			(1		)	—			12
Other	4			(5		)	(1		)	(2		)
Total electric revenue change	$	96		$	(71	)	$	(1	)	$	24
Fuel and purchased power change:
Fuel:
Fuel, purchased power and transportation costs included in base rates	$	(21	)	$	—		$	—		$	(21	)
Recovery of FAC under-recovery(c)	(18		)	—			—			(18		)
Illinois pass-through power supply costs and other	—			63			2			65
Total fuel and purchased power change	$	(39	)	$	63		$	2		$	26
Net change in electric margins	$	57		$	(8	)	$	1		$	50
Natural gas margins change:
Effect of weather (estimate)(b)	$	2		$	8		$	—		$	10
Base rates (estimate)	—			2			—			2
Energy efficiency programs and environmental remediation cost riders	—			5			—			5
Gross receipts tax	1			4			—			5
Sales (excluding the impact of abnormal weather) and other	1			2			(1		)	2
Net change in natural gas margins	$	4		$	21		$	(1	)	$	24

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

(b) Represents the estimated margin impact resulting from the effects of changes in cooling and heating degree-days on electric and natural gas demand compared with the prior-year period 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 fuel costs recovered under the FAC through customer rates, with corresponding offsets to fuel expense due to amortization of a previously recorded regulatory asset.

Ameren Corporation

Ameren’s electric margins increased by $50 million, or 7%, for the three months ended March 31, 2013, compared with the same period in 2012. The following items had a favorable impact on Ameren’s electric margins:

• Weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as evidenced by a 40% increase in heating degree-days compared to the same period in 2012, which increased revenues by $36 million.

• Higher electric base rates at Ameren Missouri, effective January 2013, which increased revenues by $35 million, offset by an increase in net base fuel expense of $31 million, which was a result of higher net base fuel cost rates approved in the 2012 MoPSC rate order. Net base fuel expense is the sum of fuel, purchased power and transportation costs included in base rates ($21 million), off-system revenues ($19 million), and beginning in 2013, transmission services revenues ($9 million). Transmission services revenues of $7 million for 2012 were not included in the FAC. The $2 millionincrease in transmission services

revenues between 2013 and 2012 is included in the above table. See below for additional details regarding the FAC.

• Excluding the estimated impact of abnormal weather, rate-regulated sales volumes were flat; however, margins increased due to growth in the residential and commercial sectors at Ameren Missouri, which increased revenues by $12 million.

• Higher transmission margins, primarily at Ameren Illinois, due to the forward-looking rate calculation for 2013, which increased margins by $12 million pursuant to a 2012 FERC order. On January 1, 2013, Ameren Illinois adjusted its electric transmission rates to reflect an increase in its transmission revenue requirement, which is subject to a periodic revenue requirement reconciliation.

• Higher revenues associated with Ameren Missouri's MEEIA energy efficiency program cost recovery ($5 million) and lost revenue recovery ($2 million), effective January 2013, which increased revenues by a combined $7 million. The program cost recovery was offset by increased program cost expenses, with no overall impact on net income. See Other Operations and Maintenance Expenses in this section for

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information on a related offsetting increase in energy efficiency program costs. The lost revenue recovery is expected to recover 90% of the projected lost revenue over three years beginning in 2013. See Note 3 - Rate and Regulatory Matters under Part 1, Item 1, for further information regarding MEEIA.

• Increased gross receipts tax collections at Ameren Missouri due to higher sales as a result of colder winter weather in 2013, compared with 2012, which increased revenues by $5 million. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.

Ameren’s electric margins were unfavorably impacted by electric delivery formula ratemaking adjustments at Ameren Illinois resulting from the annual reconciliation of the revenue requirement pursuant to the IEIMA, which decreased revenues by $16 million. The reduction in revenues during the first quarter of 2013 was primarily a result of the variation in the timing and amount of expected full-year recoverable costs under formula ratemaking.

Ameren Illinois’ revenues associated with Illinois pass-through power supply costs decreased$63 million because of lower power prices on sales and customers switching to alternative retail electric suppliers. This decrease in revenues was offset by a corresponding net decrease in purchased power expense.

Ameren Missouri has a FAC cost recovery mechanism that allows Ameren Missouri to recover, through customer rates, 95% of changes in fuel, emission allowances, purchased power costs, transmission costs and MISO costs and revenues, net of off-system revenues, greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudency reviews. The MoPSC's December 2012 order authorized the inclusion of fuel additive costs and transmission revenues in the FAC starting in 2013. 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 fuel costs under the FAC through customer rates increased by $18 million, for the three months ended March 31, 2013, compared with the same period in 2012, with corresponding offsets to fuel expense to reduce the previously recognized FAC regulatory asset.

Ameren’s natural gas margins increased by $24 million, or 18%, for the three months ended March 31, 2013, compared with the same period in 2012. The following items had a favorable impact on Ameren’s natural gas margins:

• Weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as evidenced by an increase in heating degree-days of 40% in the first quarter of 2013 compared to the same period in 2012, which increased margins by $10 million.

• Net increased recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms at Ameren Illinois, which increased

revenues by $5 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.

• Increased gross receipts tax collections, primarily at Ameren Illinois, due to higher sales as a result of colder winter weather in 2013 compared with 2012, which increased revenues by $5 million. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.

• Excluding the estimated impact of abnormal weather, retail sales volumes increased 1%, primarily at Ameren Illinois, driven largely by residential customers, which increased revenues by $2 million.

• Increased natural gas rates effective in late January 2012, at Ameren Illinois, which increased revenues by $2 million.

Ameren Missouri

Ameren Missouri’s electric margins increased by $57 million, or 13%, for the three months ended March 31, 2013, compared with the same period in 2012. The following items had a favorable impact on Ameren Missouri’s electric margins:

• Higher electric base rates, effective in January 2013, which increased revenues by $35 million, offset by an increase in net base fuel expense of $31 million, which was a result of higher net base fuel cost rates approved in the 2012 MoPSC rate order. Net base fuel expense is the sum of fuel, purchased power and transportation costs included in base rates ($21 million), off-system revenues ($19 million), and beginning in 2013, transmission services revenues ($9 million). Transmission services revenues of $7 million for 2012 were not included in the FAC. The $2 millionincrease in transmission services revenues between 2013 and 2012 is included in the above table.

• Weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as evidenced by a 45% increase in heating degree-days compared to the same period in 2012, which increased revenues by $31 million.

• Excluding the estimated impact of abnormal weather, retail sales volumes increased 2% primarily in the residential and commercial sectors, which increased revenues by $13 million.

• Higher revenues associated with MEEIA energy efficiency program cost recovery ($5 million) and lost revenue recovery ($2 million), effective January 2013, which increased revenues by a combined $7 million. The program cost recovery was offset by increased program expenses, with no overall impact on net income. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency program costs. The lost revenue recovery is expected to recover 90% of the projected lost revenue over three years beginning in 2013. See Note 3 - Rate and Regulatory Matters under Part 1, Item 1, for further information regarding MEEIA.

• Increased gross receipts tax collections due to higher sales as a result of colder winter weather in 2013 compared with 2012, which increased revenues by $5 million. See Taxes

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Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.

Ameren Missouri’s natural gas margins increased by $4 million, or 17%, for the three months ended March 31, 2013, compared with the same period in 2012. The following items had a favorable impact on Ameren Missouri’s natural gas margins:

• Weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as evidenced by an increase in heating degree-days of 45% compared to the same period in 2012, which increased margins by $2 million.

• Increased gross receipts tax collections due to higher sales as a result of colder weather in 2013 compared with 2012, which increased revenues by $1 million. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.

• Excluding the estimated impact of abnormal weather, retail sales volumes increased 2%, driven largely by residential customers, which increased revenues by $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 customers switching to or from alternative retail electric suppliers and 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 $8 million, or 3%, for the three months ended March 31, 2013, compared with the same period in 2012. Ameren Illinois’ electric margins were unfavorably impacted by electric delivery formula ratemaking adjustments at Ameren Illinois resulting from the annual reconciliation of the revenue requirement pursuant to the IEIMA, which decreased revenues by $16 million. The reduction in revenues during the first quarter of 2013 was primarily a result of the variation in the timing and amount of expected full-year recoverable costs under formula ratemaking.

The following items had a favorable impact on Ameren Illinois’ electric margins:

• Higher transmission margins due to the forward-looking rate calculation for 2013, which increased margins by $9 million pursuant to a 2012 FERC order. On January 1, 2013, Ameren Illinois adjusted its electric transmission rates to reflect an increase in its transmission revenue requirement, which is subject to a periodic revenue requirement reconciliation.

• Weather conditions in the first quarter of 2013 were normal compared to warmer-than-normal conditions in the first quarter of 2012, as evidenced by a 39% increase in heating degree-days compared to the same period in 2012, which increased revenues by $5 million.

Ameren Illinois’ natural gas margins increased by $21 million, or 19%, for the three months ended March 31, 2013, compared with the same period in 2012. The following items had a favorable impact on Ameren Illinois’ natural gas margins:

• Weather conditions in the first quarter of 2013 were normal compared to warmer-than-normal conditions in the first quarter of 2012, as evidenced by a 39% increase in heating degree-days compared to the same period in 2012, which increased margins by $8 million.

• Net increased recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms, which increased revenues by $5 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.

• Increased gross receipts tax collections due to higher sales as a result of colder winter weather in 2013 compared with 2012, which increased revenues by $4 million. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.

• Excluding the estimated impact of abnormal weather, retail sales volumes increased 1%, driven largely by the residential sector, which increased revenues by $2 million.

• Increased natural gas rates effective in late January 2012, which increased revenues by $2 million.

Other Operations and Maintenance Expenses

Ameren Corporation

Other operations and maintenance expenses were $30 million higher in the first quarter of 2013, as compared with the first quarter of 2012.

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

• An $8 million increase in labor costs, primarily because of wage increases and because of staff additions at Ameren Illinois due to the requirements of IEIMA.

• A $5 million increase in energy efficiency and environmental remediation costs at Ameren Illinois. These costs were recovered through customer billings and were offset by increased electric and natural gas revenues, with no overall impact on net income.

• A $5 million increase in energy efficiency program costs due to the requirements of MEEIA at Ameren Missouri. These costs were recovered through customer billings and were offset by increased electric revenues, with no overall impact on net income.

• A $3 million increase in non-storm-related distribution maintenance expenditures at Ameren Illinois, primarily related to increased vegetation control work.

• A $3 million increase in transmission and distribution expenses at Ameren Illinois, primarily because of gas pipeline integrity compliance.

• A $3 million increase in plant maintenance costs, primarily due to the 2013 Callaway energy center refueling and

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maintenance outage.

Variations in other operations and maintenance expenses in Ameren's business segments and for the Ameren Companies for the three months ended March 31, 2013, compared with the same period in 2012, were as follows:

Ameren Missouri

Other operations and maintenance expenses were $19 million higher in the first quarter of 2013, as compared with the first quarter of 2012.

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

• A $5 million increase in energy efficiency program costs due to the requirements of MEEIA, as discussed above in Margins.

• A $3 million increase in labor costs, primarily because of wage increases.

• A $3 million increase in plant maintenance costs, primarily due to the 2013 Callaway energy center refueling and maintenance outage.

• A $2 million increase in employee benefit costs, primarily due to higher pension expense. These costs were recovered through customer billings and were offset by increased electric and natural gas revenues, with no overall impact on net income.

• A $2 million increase in storm-related repair costs, primarily due to major storms in the first quarter of 2013.

Ameren Illinois

Other operations and maintenance expenses were $8 million higher in the first quarter of 2013, as compared with the first quarter of 2012.

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

• A $5 million increase in energy efficiency and environmental remediation costs, as discussed above in Margins.

• A $3 million increase in non-storm-related electric distribution maintenance expenditures, primarily related to increased vegetation control work.

• A $3 million increase in transmission and distribution expenses, primarily because of gas pipeline integrity compliance.

• A $2 million increase in labor costs, primarily because of wage increases and staff additions due to the requirements of the IEIMA.

Other operations and maintenance expenses decreased between periods because of a $3 million reduction in employee benefit costs, primarily due to lower postretirement expense.

Depreciation and Amortization

Ameren Corporation

Ameren's depreciation and amortization expenses increased by $8 million in the first quarter of 2013, as compared with the first quarter of 2012, due to increased expenses at Ameren Missouri and Ameren Illinois discussed below.

Variations in depreciation and amortization expenses in Ameren's business segments and for the Ameren Companies for the three months ended March 31, 2013, compared with the same period in 2012, were as follows:

Ameren Missouri

Depreciation and amortization expenses increased by $3 million, primarily due to the timing of distribution infrastructure capital additions and the 2012 MoPSC electric order resulting in higher amortization of energy efficiency costs, which were reflected in rates effective in January 2013.

Ameren Illinois

Depreciation and amortization expenses increased by $6 million, primarily due to new electric depreciation rates, which were largely driven by a reduction in the useful lives of existing electric meters that are being replaced with advanced metering infrastructure pursuant to the IEIMA, and increased infrastructure additions.

Taxes Other Than Income Taxes

Ameren Corporation

Taxes other than income taxes increased by $9 million in the first quarter of 2013, as compared with the first quarter of 2012, primarily due to an increase in gross receipts taxes at Ameren Missouri and Ameren Illinois. These increased taxes are offset by increased revenues, with no overall impact on net income. See Note 1 - Summary of Significant Accounting Policies under Part I, Item 1, of this report for additional information

Variations in taxes other than income taxes in Ameren's business segments and for the Ameren Companies for the three months ended March 31, 2013, compared with the same period in 2012, were as follows:

Ameren Missouri

Taxes other than income taxes increased by $6 million, primarily due to an increase in gross receipts taxes as a result of increased sales.

Ameren Illinois

Taxes other than income taxes increased by $3 million, primarily due to an increase in gross receipts taxes as a result of increased sales, partially offset by a decrease in property taxes, primarily as a result of lower state and local assessments.

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Other Income and Expenses

Ameren Corporation

Other income, net of expenses, increased by $5 million in the first quarter of 2013, as compared with the first quarter of 2012, primarily because decreased donations at Ameren Illinois more than offset increased other miscellaneous expenses at Ameren Missouri, as noted below.

Variations in other income, net of expenses, in Ameren's business segments and for the Ameren Companies for the three months ended March 31, 2013, compared with the same period in 2012, were as follows:

Ameren Missouri

Other income, net of expenses, decreased by $3 million, primarily due to increased other miscellaneous expenses.

Ameren Illinois

Other income, net of expenses, increased by $8 million, primarily due to decreased donations because of the absence in 2013 of the one-time $7.5 million donation to the Illinois Science and Energy Innovation Trust pursuant to the IEIMA in connection with participation in the formula ratemaking process in 2012.

Interest Charges

Ameren Corporation

Interest charges increased by $3 million in the first quarter of 2013, as compared with the first quarter of 2012, primarily because of higher interest charges at Ameren Missouri, partially offset by lower interest charges at Ameren Illinois.

Variations in interest charges in Ameren's business segments and for the Ameren Companies for the three months ended March 31, 2013, compared with the same period in 2012, were as follows:

Ameren Missouri

Interest charges increased by $4 million, primarily because of a rate adjustment on the allowed reimbursable rate for pre-MEEIA energy efficiency programs, which were reflected as a regulatory asset on Ameren Missouri’s balance sheet, partially offset by the impacts of the September 2012 issuance of $485 million of 3.90% senior secured notes, which were used to repurchase $71 million of 6.00% senior secured notes, $121 million of 6.70% senior secured notes, and $57 million of 5.10% senior secured notes.

Ameren Illinois

Interest charges decreased by $2 million, primarily because of the impacts of the August 2012 issuance of $400 million of 2.70% senior secured notes, which were used to repurchase $87 million of 9.75% senior secured notes and $194 million of 6.25% senior secured notes.

Income Taxes

The following table presents effective income tax rates for Ameren's business segments and for the Ameren Companies for the three months ended March 31, 2013, and 2012:

	Three Months
	2013		2012
Ameren(a)	38	%	37	%
Ameren Missouri(a)	32	%	35	%
Ameren Illinois(a)	38	%	39	%

(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.

Ameren Corporation

Ameren's effective tax rate was higher in the first quarter of 2013, as compared with the first quarter of 2012, primarily due to valuation allowances on deferred tax assets related to charitable contribution deductions and state tax credits that we expect we will not be able to use before the expiration of the carryforward periods.

Variations in effective tax rates in Ameren's business segments and for the Ameren Companies for the three months ended March 31, 2013, compared with the same period in 2012, were as follows:

Ameren Missouri

Ameren Missouri's effective tax rate was lower primarily because of a decrease in reserves for uncertain tax positions along with tax benefits related to the manufacturing deduction in the first quarter of 2013.

Ameren Illinois

Ameren Illinois' effective tax rate was lower, primarily because of the increased benefit of tax credits in the first quarter of 2013.

Loss from Discontinued Operations, Net of Taxes

See Note 2 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for information regarding Ameren’s decision to exit the Merchant Generation business and divest New AER and the Elgin, Gibson City and Grand Tower energy centers.

The loss from discontinued operations, net of taxes decreased to $199 million, in the first quarter of 2013, from $442 million, in the first quarter of 2012.

As the New AER disposal group met the discontinued operations criteria at March 31, 2013, Ameren evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value of the disposal group, based on the transaction agreement to sell New AER to IPH, less cost to sell. The fair value was based on the terms of Ameren’s agreement to divest New AER to IPH. Ameren will receive no

63

cash proceeds from IPH for the divestiture of New AER. Ameren recorded a pretax charge to earnings of $155 million for the three months ended March 31, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. Ameren estimated the impairment loss of the disposal group based on the estimated fair value pursuant to the terms in the transaction agreement with IPH, using information currently available, and assuming an expected fourth quarter 2013 closing. Actual operating results, derivative market values, capital expenditures, and other items will impact the ultimate loss recognized to reduce the carrying value of the New AER disposal group to its actual fair value less cost to sell, which will be recorded in discontinued operations after all of the information becomes available. In addition, any curtailment gain related to Ameren's pension and postretirement plans will be recorded when the related employees terminate employment with Ameren. The ultimate impairment loss may differ materially from the estimated loss recorded in the first quarter of 2013.

Ameren recognized the excess of the tax basis over the financial reporting basis of its stock investment in AER when it became apparent, in the three months ended March 31, 2013, that the temporary difference would reverse. This change in basis resulted in a discontinued operations deferred tax expense of $98 million, which was partially offset by the expected tax benefits of $63 million related to the pretax loss from discontinued operations including the impairment charge recorded in the first quarter of 2013. The final tax basis of the AER disposal group and the related tax benefit resulting from the transaction agreement with IPH are dependent upon taxable losses utilized by the disposal group through the closing and the resolution of tax matters under audit, including the adoption of recently issued guidance from the IRS related to tangible property repairs and other matters. As a result, tax expense and benefits realized in discontinued operations may differ materially from those recorded as of March 31, 2013.

As the Elgin, Gibson City, and Grand Tower energy centers disposal group met the discontinued operations criteria at March 31, 2013, we evaluated whether any impairment existed by comparing the disposal group’s carrying value to the fair value of the disposal group less cost to sell. The fair value was based on the appraised value of these three gas-fired energy centers. In December 2012, Ameren recorded a noncash long-lived asset impairment charge to reduce the carrying value of AER’s energy centers, including the Elgin, Gibson City, and Grand Tower energy centers, to their estimated fair values under the accounting guidance for held and used assets. An immaterial impairment was recorded by Ameren for the three gas-fired energy centers during the three months ended March 31, 2013, as the December 2012 held and used asset impairment charge reduced these energy centers’ disposal group carrying value to their estimated fair value of $133 million.

Merchant Generation's electric margins decreased by $77 million, or 53%, for the three months ended March 31, 2013, compared with the same period in 2012. Merchant Generation's electric margins were unfavorably impacted by lower sales prices, primarily due to the expiration of higher-priced hedges,

which decreased revenues by $81 million and net unrealized MTM activity, primarily on nonqualifying power hedges, which decreased margins by $17 million.

Merchant Generation's electric margins were favorably impacted by higher retail sales to sell power to residential and small commercial customers in Illinois and overall higher average spot market prices in the first quarter of 2013 compared with the same period in 2012. Consequently, Merchant Generation's sales volume grew, which increased revenues by $64 million. This increase was mitigated by a $27 million increase in production volume and other costs and a $16 million increase in purchased power and other costs. Merchant Generation's average capacity factor increased to 77% in the first quarter of 2013, compared with 65% in the same period in 2012. Merchant Generation's equivalent availability factor decreased to 85% in 2013, compared with 88% in 2012.

Other operations and maintenance expenses were $11 million lower at Merchant Generation in the first quarter of 2013, as reduced plant maintenance costs of $14 million, primarily due to fewer outages and reduced charges for canceled projects of $4 million more than offset reduced gains in property sales of $9 million.

Depreciation and amortization expenses decreased by $23 million, primarily because the long-lived asset impairments recorded in the first and fourth quarters of 2012 caused a reduction in the carrying value of net plant assets. Interest charges decreased by $4 million, primarily because of increased capitalized interest due to the Newton energy center scrubber project.

The sharp decline in the market price of power in early 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 to evaluate, during the first quarter of 2012, whether the carrying values of its coal-fired energy centers were recoverable. 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.

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 primarily of 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 agreement 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

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Ameren Illinois may reduce their credit agreement 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 standards, 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 to finance their operations appropriately, to fund scheduled debt maturities, and to maintain financial strength and flexibility.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 2 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for additional information. As a result of the IPH transaction and Ameren’s intention to sell the Elgin, Gibson City and Grand Tower energy centers to a third-party, the Merchant Generation business was classified as discontinued operations for all periods presented in this report. While it remains a business of Ameren, the Merchant Generation segment will seek to fund its operations internally and therefore will seek not to rely on financing from Ameren or external, third-party sources. The Merchant Generation segment will seek to defer or reduce capital and operating expenses, sell certain assets, and to take other actions as necessary to fund its operations internally while maintaining safe and reliable operations. The transaction agreement with IPH contains customary covenants of Ameren that AER will be operated in the ordinary course prior to closing.

The following table presents net cash provided by (used in) operating, investing and financing activities for the three months ended March 31, 2013, and 2012:

	Net Cash Provided By Operating Activities							Net Cash (Used In) Investing Activities									Net Cash (Used In) Financing Activities
	2013		2012		Variance			2013			2012			Variance			2013			2012			Variance
Ameren(a) - continuing operations	$	342	$	304	$	38		$	(291	)	$	(292	)	$	1		$	(99	)	$	(113	)	$	14
Ameren(a) - discontinued operations	37		79		(42		)	(12		)	(19		)	7			—			—			—
Ameren Missouri	68		107		(39		)	(129		)	(204		)	75			(86		)	(101		)	15
Ameren Illinois	271		289		(18		)	(138		)	(86		)	(52		)	(40		)	(37		)	(3		)

(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 associated with continuing operations increased in the first three months of 2013, compared with the first three months of 2012. The following items contributed to the increase in cash from operating activities during the first three months of 2013, compared with the same period in 2012:

• Electric and natural gas margins, as discussed in Results of Operations, increased by $74 million.

• A net $35 million decrease in collateral posted with counterparties primarily due to changes in the market prices of power and natural gas and in contracted commodity volumes at Ameren Illinois as well as 2013 credit rating upgrades.

• A $31 million increase in natural gas commodity over-recovered costs under the PGA, primarily related to Ameren Illinois.

• Cash flows associated with Ameren Missouri’s under-recovered FAC costs, which increased by $30 million. Recoveries outpaced deferrals in the first quarter of 2013 by $20 million, while deferrals and refunds outpaced recoveries in the first quarter of 2012 by $10 million.

• During the first quarter of 2013, coal inventory levels were lower than year end resulting in a $12 million decrease, while in the first quarter of 2012, coal inventory increased

$18 million primarily due to additional tons held in inventory because generation levels were below expected levels due to market conditions and warmer-than-normal weather conditions.

• The absence of $28 million in severance payments made in 2012 as a result of the voluntary separation offers extended to Ameren Missouri and Ameren Services employees in the fourth quarter of 2011.

• A $9 million decrease in payments related to the MISO liability due, in part, to fewer purchases in December 2012 as compared with December 2011.

The following items reduced the increase in Ameren's cash from operating activities during the first three months of 2013 compared with the same period in 2012:

• A $161 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 2012, compared with December 2011.

• A $35 million increase in pension and postretirement benefit plan contributions caused by the timing of payments in the first quarter of 2013.

• The absence in 2013 of court registry receipts and payments. In 2012, Ameren Missouri received $21 million from the Circuit Court of Stoddard County's registry as a result of a Missouri Court of Appeal ruling upholding the

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MoPSC's January 2009 electric rate order. This amount was partially offset by the absence of $2 million of Ameren Missouri receivables, which were paid into the Cole County Circuit Court registry in 2012 in connection with the appeal of the MoPSC's 2010 electric rate order.

Ameren’s cash from operating activities associated with discontinued operations decreased in the first three months of 2013, compared with the first three months of 2012, primarily attributable to a $60 million decrease in electric margins, excluding impacts of noncash MTM transactions, as discussed in Result of Operations.

Ameren Missouri

Ameren Missouri’s cash from operating activities decreased in the first three months of 2013, compared with the first three months of 2012. The following items contributed to the decrease in cash from operating activities during the first three months of 2013, compared with the same period in 2012:

• A $91 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 2012, compared with December 2011.

• A $35 million increase in income tax payments resulting primarily from the timing in payment of income taxes in 2012 partially offset by a reduction in accelerated depreciation deductions.

• A $20 million increase in property tax payments caused by the timing of payments, partially offset by higher assessed property tax values.

• The absence in 2013 of court registry receipts and payments. In 2012, Ameren Missouri received $21 million from the Circuit Court of Stoddard County's registry as a result of a Missouri Court of Appeal ruling upholding the MoPSC's January 2009 electric rate order. This amount was partially offset by the absence of $2 million of receivables, which were paid into the Cole County Circuit Court registry in 2012 in connection with the appeal of the MoPSC's 2010 electric rate order.

• A $15 million increase in pension and postretirement benefit plan contributions caused by the timing of payments in the first quarter of 2013.

The following items partially offset the decrease in Ameren Missouri’s cash from operating activities during the first three months of 2013, compared with the same period in 2012:

• Electric and natural gas margins, as discussed in Results of Operations, increased by $61 million.

• Cash flows associated with the under-recovered FAC costs, which increased by $30 million. Recoveries outpaced deferrals in the first quarter of 2013 by $20 million, while deferrals and refunds outpaced recoveries in the first quarter of 2012 by $10 million.

• During the first quarter of 2013, coal inventory levels were lower than year-end resulting in a $12 million decrease, while in the first quarter of 2012, coal inventory increased

$18 million primarily due to additional tons held in inventory because generation levels were below expected levels due to market conditions and warmer-than-normal weather conditions.

• The absence of $25 million in severance payments made in 2012 as a result of the voluntary separation offers extended to employees in the fourth quarter of 2011.

Ameren Illinois

Ameren Illinois’ cash from operating activities decreased in the first three months of 2013, compared with the first three months of 2012. The following items contributed to the decrease in cash from operating activities during the first three months of 2013, compared with the same period in 2012:

• A $71 million decrease in cash collections from customer receivables primarily caused by milder weather in December 2012, compared with December 2011.

• A $26 million decrease in income tax refunds resulting primarily from a reduction in accelerated depreciation deductions.

• A $12 million increase in pension and postretirement benefit plan contributions caused by the timing of payments in the first quarter of 2013.

The following items partially offset the decrease in Ameren Illinois’ cash from operating activities during the first three months of 2013, compared with the same period in 2012:

• A net $38 million decrease in collateral posted with counterparties primarily due to changes in the market prices of power and natural gas and in contracted commodity volumes as well as 2013 credit rating upgrades.

• A $24 million increase in natural gas commodity over-recovered costs under the PGA.

• Electric and natural gas margins, as discussed in Results of Operations, increased by $13 million.

• A $9 million decrease in payments related to the MISO liability due, in part, to fewer purchases in December 2012 as compared with December 2011.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities associated with continuing operations in the first three months of 2013 was comparable with the same period in 2012. Capital expenditures increased $30 million but were offset by a $27 million decrease in nuclear fuel expenditures due to timing of purchases.

Cash flows used in investing activities associated with Ameren’s discontinued operations decreased during the first three months of 2013, compared with the same period in 2012, primarily due to reduced capital expenditures as a result of the deceleration of construction of scrubbers at the Newton energy centers partially offset by property sale proceeds of $16 million received from the sale of Medina Valley energy center’s net property and plant in 2012.

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Ameren Missouri’s cash used in investing activities decreased during the first three months of 2013, compared with the same period in 2012. Capital expenditures decreased $20 million primarily because of reduced expenditures for energy center projects. Cash flows used in investing activities also decreased due to repayments of $24 million of money pool advances and a $27 million decrease in nuclear fuel expenditures due to timing of purchases.

Ameren Illinois’ cash used in investing activities increased during the first three months of 2013, compared with the same period in 2012, primarily due to increased capital expenditures of $47 million for maintenance and reliability capital projects. In addition, Ameren Illinois contributed $5 million of surplus funds to the utility money pool.

See Note 10 - 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 associated with continuing operations decreased during the three months ended March 31, 2013, compared with the same period in 2012. In the first quarter of 2012, Ameren repaid $22 million of its short-term debt with no such payments in the first quarter of 2013. Ameren declared common stock dividends totaling $97 million in both the first quarter of 2013 and 2012. Dividends paid on common stock increased $7 million in 2013, as compared with 2012, as a result of 2012 non-cash financing activity of $7 million due to the timing of DRPlus common stock dividend funding.

Ameren Missouri’s net cash used in financing activities decreased during the three months ended March 31, 2013, compared with the same period in 2012, as a result of a $10 million decrease in common stock dividends and net money pool borrowings of $5 million.

Ameren Illinois’ net cash used in financing activities increased during the three months ended March 31, 2013, compared with the same period in 2012. Common stock dividends decreased by $22 million, but were more than offset by a $24 million net repayment of money pool borrowings.

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, and drawings under committed bank credit agreements, or commercial paper issuances. See Note 4 - Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information on credit agreements, short-term borrowing activity, commercial paper issuances, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements.

The following table presents the committed 2012 Credit Agreements of Ameren, Ameren Missouri, and Ameren Illinois and the credit capacity available under such agreements, considering reductions for letters of credit, as of March 31, 2013:

	Expiration	Borrowing Capacity		Credit Available
Amerenand Ameren Missouri:
2012 Missouri Credit Agreement(a)(b)	November 2017	$	1,000	$	1,000
Ameren and Ameren Illinois:
2012 Illinois Credit Agreement(a)(b)	November 2017	1,100		1,100
Ameren:
Less: Letters of credit		(c)		(37		)
Total		$	2,100	$	2,063

(a) Certain Ameren subsidiaries not party to the 2012 Credit Agreements may access these credit agreements through intercompany borrowing arrangements.

(b) Each credit agreement expires on November 14, 2017. The borrowing sublimits of Ameren Missouri and Ameren Illinois will mature and expire on November 13, 2013, subject to extension on a 364-day basis or for a longer period upon notice by the respective borrower of receipt of any and all required federal or state regulatory approvals, as permitted under each credit agreement, but in no event later than November 14, 2017. Ameren Missouri and Ameren Illinois plan to seek any and all required state regulatory approval necessary to extend the maturity date of their borrowing sublimits under the 2012 Credit Agreements to November 14, 2017.

(c) Not applicable.

The 2012 Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper

programs. Any of the 2012 Credit Agreements are available to Ameren to support borrowings under Ameren’s commercial paper program, subject to borrowing sublimits. The 2012 Missouri Credit Agreement is available to support borrowings under

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Ameren Missouri’s commercial paper program, and the 2012 Illinois Credit Agreement is available to support borrowings under Ameren Illinois’ commercial paper program.

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 by Ameren Missouri. The authorization terminates on March 31, 2014. In September 2012, FERC issued an order authorizing the issuance of up to $1 billion of short-term debt securities by Ameren Illinois. The authorization terminates on September 30, 2014.

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 agreements or to other short-term borrowing arrangements.

Long-term Debt and Equity

The Ameren Companies did not have any issuances, redemptions, repurchases, or maturities of long-term debt or preferred stock during the first three months of 2013 or 2012. The Ameren Companies did not have any issuances of common stock during the first three months of 2013 or 2012. For additional information, see Note 5 - Long-term Debt and Equity Financings under Part I, Item 1, of this report.

The Ameren Companies may sell securities registered under their effective registration statements if market conditions and capital requirements warrant such sales. 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 4 - Short-term Debt and Liquidity and Note 5 - 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 March 31, 2013, 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.

Discontinued Operations

Merchant Generation’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 its indenture, described in Note 5 - 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. During the first quarter of 2013, Genco’s interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and Genco expects the ratio to remain less than this minimum level through at least 2015. As a result, Genco’s ability to borrow additional funds from external, third party sources is restricted. 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. While it remains a business of Ameren, the Merchant Generation segment, including Genco, seeks to fund its operations internally and therefore seeks not to rely on financing from Ameren or external, third-party sources.

Should a financing need arise, Genco's sources of liquidity include available cash on hand, a return of money pool advances and money pool borrowings at the discretion of Ameren. On March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. In 2013, Genco expects to receive at least an additional $33 million depending on the appraised value of these energy centers or the value realized from Medina Valley's sale to a third-party. These put option proceeds, along with cash on hand and the return of money pool advances are Genco's primary sources of liquidity. Based on current projections, including the amount received related to the put option, Genco expects operating cash flows to approximate nonoperating cash flow requirements in 2013 and daily working capital needs to be sufficiently covered by cash on hand.

Dividends

Ameren declared, and paid to its stockholders, common stock dividends totaling $97 million, or 40 cents per share during the first three months of 2013 (2012 - $97 million declared or 40

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cents per share). On April 23, 2013, Ameren’s board of directors declared a quarterly common stock dividend of 40 cents per share payable on June 28, 2013, to stockholders of record on June 12, 2013.

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 March 31, 2013, 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 each of the subsequent four six-month periods ending September 30, 2013, March 31, 2014, September 30, 2014, or March 31, 2015. As a result, Genco was restricted from paying dividends as of March 31, 2013, and we expect Genco to be unable to pay dividends on its common stock through at least March 31, 2016.

See Note 2 - Divestiture Transactions and Discontinued Operations 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 March 31, 2013, 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 Missouri and Ameren Illinois to their parent, Ameren Corporation, for the three months ended March 31, 2013, and 2012:

	Three Months
	2013		2012
Ameren Missouri	$	90	$	100
Ameren Illinois	15		37
Dividends paid by Ameren	97		90

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 10 - Commitments and Contingencies under Part I, Item 1, of this report. See Note 12 - Retirement Benefits to our financial statements under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan.

At March 31, 2013, total other obligations related to the procurement of coal, natural gas, nuclear fuel, purchased power, methane gas, equipment and meter reading services, among other agreements, at Ameren, Ameren Missouri, and Ameren

Illinois were $7,515 million, $5,151 million, and $2,316 million, respectively. Total unrecognized tax benefits at March 31, 2013, which were not included in the previous totals, for Ameren, Ameren Missouri, and Ameren Illinois were $190 million, $126 million, and $4 million, respectively.

Off-Balance-Sheet Arrangements

At March 31, 2013, none of the Ameren Companies had 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. See Note 9 - Related Party Transactions under Part I, Item 1, of this report for Ameren (parent) guarantees on behalf of its subsidiaries.

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	BBB-	BBB
Commercial paper	P-3	A-2	F2
Ameren Missouri:
Issuer/corporate credit rating	Baa2	BBB	BBB+
Secured debt	A3	A-	A
Ameren Illinois:
Issuer/corporate credit rating	Baa2	BBB	BBB-
Secured debt	A3	A-	BBB+
Senior unsecured debt	Baa2	BBB	BBB

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.

Collateral Postings

Any adverse changes in credit ratings relating to Ameren’s continuing operations 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 March 31, 2013, were $45 million, $14 million, and $31 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively. Cash collateral posted by external

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counterparties with Ameren and Ameren Illinois was $2 million and $2 million, respectively, at March 31, 2013. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at March 31, 2013, could have resulted in Ameren, Ameren Missouri, or Ameren Illinois being required to post additional collateral or other assurances for certain trade obligations amounting to $140 million, $62 million, and $78 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments at current credit ratings. If market prices were 15% higher than March 31, 2013, levels in the next 12 months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois could be required to post additional collateral or other assurances for certain trade obligations up to approximately $4 million, $4 million, and $- million, respectively. If market prices were 15% lower than March 31, 2013, levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois could be required to post additional collateral or other assurances for certain trade obligations up to approximately $25 million, $- million, and $25 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 and simultaneously 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 are focused on minimizing the gap between allowed and earned returns on equity. On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. This divestiture will position Ameren to focus exclusively on its rate-regulated electric, natural gas and transmission operations, clarifying Ameren’s strategic direction. Ameren intends to allocate its capital resources to those business opportunities which 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 2013 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 December 2012, the ICC issued an order with respect to Ameren Illinois' update IEIMA filing approving an electric delivery service revenue requirement that was a $70 million

decrease from the requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The new rates became effective on January 1, 2013.

• We believe that Ameren Illinois' participation in the performance-based formula ratemaking framework pursuant to the IEIMA 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. However, the ICC's orders in 2012 for Ameren Illinois' initial and update rate filings jeopardize Ameren Illinois' ongoing ability to implement infrastructure improvements to the extent and on the timetable envisioned in the IEIMA. Ameren Illinois has appealed both of the ICC's 2012 electric rate orders to the courts and is also seeking a legislative solution to address the ICC's implementation of the IEIMA. Until the uncertainty surrounding how the Illinois law will ultimately be implemented is removed, Ameren Illinois is slowing IEIMA capital spending with a corresponding negative effect on the job creation that the legislature sought to effectuate with the law. Ameren Illinois still intends to meet its IEIMA capital spending requirements.

• On March 14, 2013, the Illinois General Assembly passed legislation, which, if enacted, would result in certain amendments to the IEIMA that would modify its implementation. The passed legislation, Senate Bill 9, clarified the provisions in the IEIMA that require the year-end rate base be used to calculate the revenue requirement and that the interest applied to the revenue requirement reconciliation and return on equity collar adjustments would be consistent with the company’s weighted average return calculated under the formula rate. Additionally, the legislation specifies the use of year-end capital structure for both the revenue requirement and the revenue requirement reconciliation. On May 5, 2013, the Illinois Governor vetoed this legislation. If this legislation is ultimately enacted through a legislative override in 2013, Ameren Illinois will submit revisions to its April 19, 2013 update filing based on the new law.

• 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' 2013 electric delivery service revenues will be based on its 2013 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. The 2013 revenue requirement is expected to be higher than the 2012 revenue requirement due to expected increases in recoverable costs and rate base growth, even though the amount added to the monthly average yields of the 30-year United States treasury bonds decreased to 580 basis points in 2013 from 590 basis points in 2012.

• On April 19, 2013, Ameren Illinois filed its annual electric delivery formula rate update with the ICC based on 2012 recoverable costs and expected net plant additions for 2013. Pending ICC approval, the update filing will result in a $30 million decrease in Ameren Illinois’ electric delivery revenue requirement beginning in January 2014. The filing includes a

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proposed refund to customers of the 2012 revenue requirement reconciliation of approximately $50 million. An expected refund was recorded in 2012 as a regulatory liability. In the filing, the proposed refund is partially offset by an annual revenue requirement increase of approximately $20 million primarily due to increased recoverable costs over 2011 levels. The filing is based on an electric delivery service revenue requirement of $785 million, before consideration of the 2012 revenue requirement reconciliation refund. An ICC decision with respect to the April 2013 update filing is expected in December 2013 and will establish rates for 2014.

• In January 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service by $50 million. In an attempt to reduce regulatory lag, Ameren Illinois used a future test year, 2014, in this proceeding. A decision in this proceeding is required by December 2013.

• In December 2012, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $260 million, including $84 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 also includes $80 million for recovery of the costs associated with energy efficiency programs under the MEEIA. The remaining annual increase of $96 million approved by the MoPSC was for energy infrastructure investments and other non-fuel costs, including $10 million for increased pension and other post-employment benefit costs and $6 million for increased amortization of regulatory assets. The new rates became effective on January 2, 2013.

• The MoPSC's December 2012 electric rate order approved Ameren Missouri's implementation of MEEIA megawatthour savings targets, energy efficiency programs, and associated cost recovery mechanisms and incentive awards. Beginning in 2013, Ameren Missouri will invest approximately $147 million over the next three years for energy efficiency programs. The order allows for Ameren Missouri to collect its program costs and 90% of its projected lost revenue from customers over the same three years 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 order or potentially with the future adoption of a rider mechanism.

• As they continue to experience cost recovery pressures, Ameren Missouri and Ameren Illinois expect to seek regular electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. Ameren Missouri and Ameren Illinois will also seek

legislative solutions to address cost recovery pressures. These pressures include a weak economy, customer conservation efforts, the impacts of energy efficiency programs, increased investments and expected future investments for environmental compliance, system reliability improvements, and new baseload capacity, including renewable energy 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.

• 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 made by Ameren Missouri after the loss of Noranda's load in 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 MoPSC and a group of large industrial customers appealed the Cole County Circuit Court’s ruling to the Missouri Court of Appeals in June 2012. It is possible that the MoPSC could order additional refunds of approximately $26 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 issued. 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 due to the loss of load caused by the severe 2009 ice storm 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 no longer seek to recover from customers the sum covered by the accounting authority order.

• 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.

• Ameren Missouri's Callaway energy center's scheduled refueling and maintenance outage began on April 8, 2013. The expected duration of this outage is approximately 40 days. During a scheduled outage, which occurs every 18 months, maintenance and purchased power costs increase and the amount of excess power available for sale decreases versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC resulting in limited impact to earnings. Electric operating revenues in 2013 will not offset the additional maintenance costs incurred during the 2013 outage, because revenues relating to the additional maintenance costs are recovered over 18 months.

• Ameren Missouri continues to evaluate its longer-term needs for new baseload and peaking electric generation

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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 that could be prohibitive at some of Ameren Missouri's coal-fired energy centers, particularly at its Meramec energy center. 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 continues to pursue its plans to invest in electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The first project, Illinois Rivers, involves the building of 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 and right-of-way acquisitions are scheduled to commence in late 2013 after receipt of a certificate of public convenience and necessity, which ATXI requested from the ICC in November 2012. Construction is expected to begin in 2014. 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 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 through 2019. FERC has approved transmission rate incentives for the three MISO approved projects as well as for the Big Muddy River project. The Big Muddy River project, located primarily in southern Illinois, may be evaluated for inclusion in MISO's future transmission expansion plans. Separate from the ATXI projects discussed above, Ameren Illinois expects to invest approximately $1 billion in electric transmission assets over the next five years to address load growth and reliability requirements.

• In November 2012, FERC approved a forward-looking rate calculation with an annual revenue requirement reconciliation for Ameren Illinois' electric transmission business. Based on its forward-looking rate calculation, on January 1, 2013, Ameren Illinois adjusted its electric transmission rates to reflect an increase in its transmission revenue requirement of $29 million. The increase in Ameren Illinois' transmission revenue requirement is subject to an annual revenue requirement reconciliation, which could result in an adjustment to revenues based on the actual revenue requirement in 2013.

• For additional information regarding recent rate orders and related appeals, pending requests filed with state and federal regulatory commissions, the FAC prudence reviews, Taum Sauk matters, and separate FERC orders impacting Ameren Missouri and Ameren Illinois, see Note 3 - Rate and Regulatory Matters, Note 10 - Commitments and Contingencies and Note 11 - 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.

Discontinued Operations

• On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 2 - Divestiture Transactions and Discontinued Operations under Part I, Item 1 of this report for additional information. Under the terms of the transaction agreement, Ameren is required to operate its Merchant Generation business in the ordinary course through the transaction closing date expected in the fourth quarter of 2013.

• Completion of the New AER sale to IPH is subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC. On April 16, 2013, AER and Dynegy filed with FERC an application for approval of AER’s divestiture of New AER and Genco’s sale of the Elgin, Gibson City and Grand Tower gas-fired energy centers to Medina Valley. As a condition to IPH’s obligation to complete the acquisition of New AER, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS. AER and Dynegy filed a transfer request with the Illinois Pollution Control Board on May 2, 2013.

• Ameren has commenced a sale process for the Elgin, Gibson City and Grand Tower gas-fired energy centers and expects a third-party sale will be completed during 2013.

• Effective with its conclusion that the New AER disposal group and the Elgin, Gibson City and Grand Tower energy centers disposal group each met the criteria for discontinued operations presentation, Ameren suspended recording depreciation on these assets in March 2013.

• Based on current projections for 2013 excluding the put option receipts, AER expects its operating cash flows to approximate its nonoperating cash flow requirements in 2013. Included in this 2013 projection, AER expects to receive income tax benefits through the tax allocation agreement with Ameren and its affiliates of approximately $100 million. These estimates may change significantly depending on the taxable income or loss of Ameren and each of its subsidiaries and also assume Ameren's continued ownership of AER through 2013.

• In 2012, Marketing Company filed a request with MISO to cease operations for one of the three units at AERG's E.D. Edwards energy center. In 2013, MISO notified Marketing Company that it could not cease operations for that unit at the E.D. Edwards energy center as it is required for reliability purposes. This designation changes the pricing structure MISO uses to compensate Marketing Company for the generation from that one unit at the E.D. Edwards energy center. MISO and Marketing Company are currently in negotiations for the level of revenue required to continue to have the unit available for reliability purposes. The agreement, when reached, will be a one-year agreement retroactive to January 1, 2013. Depending on MISO’s reliability requirements, this rate structure could continue through 2016, although MISO could notify Marketing Company that it no longer needs the E.D. Edwards unit for reliability purposes and terminate the agreement after a 90-day notification. Ameren will not recognize any additional revenue from this E.D. Edwards unit until an agreement is reached. If Ameren’s ownership of AER continues through 2013 and an agreement is reached prior to the New AER

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divestiture, Ameren estimates it could record additional revenues of between $3 million and $11 million in 2013.

• The Merchant Generation segment expects to have available generation from its coal-fired energy centers of 31 million megawatthours in any given year. However, based on currently expected power prices, the Merchant Generation segment expects to generate approximately 27 million megawatthours in 2013, with approximately 96% of this generation expected to be from coal-fired energy centers.

• Power prices in the Midwest affect the amount of revenues and cash flows the Merchant Generation segment can realize by marketing power into the wholesale and retail markets. Ameren's Merchant Generation segment is adversely affected by the declining market price of power for any unhedged generation. Market prices for power have decreased over the past several years. Any unhedged forecasted generation will be exposed to market prices at the time of sale.

• As of March 31, 2013, for 2013 Marketing Company had sold forward approximately 28.5 million megawatthours, at an average price of $36 per megawatthour. Megawatthours sold forward in excess of Merchant Generation’s actual generation will be purchased from the market as needed.

• As of March 31, 2013, for 2013 Merchant Generation had hedged fuel costs for approximately 25 million megawatthours of coal and up to 27 million megawatthours of base transportation at about $23 per megawatthour.

• Upon the divestiture of New AER, subject to certain exceptions, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture and provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. See Note 9 - Related Party Transactions under Part I, Item 1 of this report for additional information.

• Ameren anticipates the reduction in employees caused by the divestiture of New AER will result in a curtailment in its pension and postretirement benefit plans. Ameren anticipates the curtailment will result in a gain to reflect the removal of AER active employees who are not yet eligible to retire. The previously accrued liability for AER employees will remain in Ameren's pension and postretirement benefit plans; however, no additional benefits will be earned after closing.

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 Ameren Companies seek to enhance regulatory frameworks and returns in order to improve cash flows, credit metrics, and related access to capital for Ameren's rate-regulated businesses.

• As of March 31, 2013, Ameren had approximately $700 million in federal income tax net operating loss carryforwards (Ameren Missouri - $175 million and Ameren Illinois - $195 million) and $90 million in federal income tax

credit carryforwards (Ameren Missouri - $12 million and Ameren Illinois - $- million). These carryforwards are expected to offset income tax liabilities for Ameren Missouri into 2014, and into 2015 for Ameren and Ameren Illinois, consistent with the tax allocation agreement. These amounts exclude any additional net operating losses that will be generated by the divestiture transaction.

• In December 2011, the IRS issued new guidance on the treatment of amounts paid to acquire, produce or improve tangible property and dispositions of such property with respect to electric transmission, distribution, and generation assets as well as natural gas transmission and distribution assets. These new rules are required to be implemented no later than January 1, 2014. In addition, in April 2013, the IRS issued new guidance defining when expenditures to maintain, replace or improve steam or electric power generation property must be capitalized. This April 2013 guidance may change how Ameren determines whether expenditures related to plant and equipment are deducted as repairs or capitalized for income tax purposes. Until Ameren completes its evaluation of the new guidance, Ameren cannot estimate its impact on Ameren's results of operation, financial position, and liquidity.

• In November 2012, the Ameren Companies entered into multiyear credit agreements that cumulatively provide $2.1 billion of credit through November 14, 2017. See Note 4 - Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information regarding the 2012 Credit Agreements. 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.

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, and 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 3 - 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

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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 to pursue market opportunities within prudent risk parameters. Our risk management policies are set by a risk management steering committee, which is composed of senior-level Ameren officers, with Ameren board of directors oversight.

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 should 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 7 - Derivative Financial Instruments under Part I, Item 1, of this report for information on the potential loss on counterparty exposure as of March 31, 2013.

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 March 31, 2013, 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 electric supplier. When 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 who use Marketing Company as their alternative retail electric supplier. As of March 31, 2013, Ameren Illinois’ balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $18 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 continued 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 and Ameren Illinois may have credit exposure associated with off-system or wholesale purchase and sale activity with nonaffiliated companies. At March 31, 2013, Ameren’s, Ameren Missouri’s, and Ameren Illinois’ combined credit exposure to nonaffiliated trading counterparties, excluding coal suppliers, deemed below investment grade either through external or internal credit evaluations, net of collateral, was less than $1 million (2012 - $1 million). At March 31, 2013, the combined credit exposures to coal suppliers deemed below investment grade either through external or internal credit evaluations, net of collateral, was less than $1 million at Ameren and at Ameren Missouri (2012- less than $1 million).

We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program. 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.

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 Missouri’s risks of changes in prices for power sales are partially hedged through sales agreements. 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).

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However, a portion of the generation capacity of Ameren Missouri is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.

If power prices were to decrease by 1% on unhedged economic generation for 2013 through 2017, Ameren and Ameren Missouri earnings would decrease by less than $1 million, based on a 36% effective tax rate.

Ameren Missouri has entered into coal contracts with various suppliers to purchase coal to manage its 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 Missouri typically hedges coal transportation forward to provide supply certainty and to mitigate transportation price volatility.

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 oil, ultra-low sulfur diesel 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 Missouri’s fuel expense could increase or decrease by $7 million annually. As of March 31, 2013, Ameren Missouri had a price cap for 95% of expected fuel surcharges in 2013.

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. Ameren Missouri has price hedges for approximately 75% of its 2013 to 2017 nuclear fuel requirements. For the years 2013 through 2017, 2015 is the only year without a fuel reloading or planned maintenance outage.

Ameren Missouri’s electric generating operations are exposed to changes in market prices for natural gas used to run CTs. Its 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 natural 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. Procurement strategies involve risk management techniques and instruments similar to those outlined earlier, as well as the management of physical assets.

The following table presents, as of March 31, 2013, 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 2013 through 2017. 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.

	2013		2014		2015 - 2017
Ameren:
Coal	100	%	100	%	96	%
Coal transportation	100		98		98
Nuclear fuel	100		99		52
Natural gas for generation	34		9		2
Natural gas for distribution(a)	43		20		5
Purchased power for Ameren Illinois(b)	100		100		50
Ameren Missouri:
Coal	100	%	100	%	96	%
Coal transportation	100		98		98
Nuclear fuel	100		99		52
Natural gas for generation	34		9		2
Natural gas for distribution(a)	37		25		10
Ameren Illinois:
Natural gas for distribution(a)	44	%	20	%	4	%
Purchased power(b)	100		100		50

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(a) Represents the percentage of natural gas price hedged for peak winter season of November through March. The year 2013 represents November 2013 through March 2014. The year 2014 represents November 2014 through March 2015. This continues each successive year through March 2018.

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

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 2013 through 2017, Ameren and Ameren Missouri’s fuel expense might increase by less than $1 million and net income might decrease by 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 10 - 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, 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 months ended March 31, 2013. 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 8 - Fair Value Measurements under Part I, Item 1, of this report for further information regarding the methods used to determine the fair value of these contracts.

Three Months Ended March 31, 2013	Ameren			Ameren Missouri			Ameren Illinois
Fair value of contracts at beginning of period, net	$	(201	)	$	3		$	(204	)
Contracts realized or otherwise settled during the period	23			(8		)	31
Changes in fair values attributable to changes in valuation technique and assumptions	—			—			—
Fair value of new contracts entered into during the period	2			1			1
Other changes in fair value	30			—			30
Fair value of contracts outstanding at end of period, net	$	(146	)	$	(4	)	$	(142	)

The following table presents maturities of derivative contracts as of March 31, 2013, 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	$	1		$	(3	)	$	—		$	—		$	(2	)
Level 2(a)	(39		)	(31		)	—			—			(70		)
Level 3(b)	(5		)	(16		)	(19		)	(34		)	(74		)
Total	$	(43	)	$	(50	)	$	(19	)	$	(34	)	$	(146	)
Ameren Missouri:
Level 1	$	—		$	(3	)	$	—		$	—		$	(3	)
Level 2(a)	(4		)	(2		)	—			—			(6		)
Level 3(b)	3			2			—			—			5
Total	$	(1	)	$	(3	)	$	—		$	—		$	(4	)
Ameren Illinois:
Level 1	$	1		$	—		$	—		$	—		$	1
Level 2(a)	(35		)	(29		)	—			—			(64		)
Level 3(b)	(8		)	(18		)	(19		)	(34		)	(79		)
Total	$	(42	)	$	(47	)	$	(19	)	$	(34	)	$	(142	)

(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

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As of March 31, 2013, 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 - Divestiture Transactions and Discontinued Operations, Note 3 - Rate and Regulatory Matters, Note 10 - Commitments and Contingencies, and Note 11 - 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:

• the request for FERC and FCC approvals, as well as the Illinois Pollution Control Board’s transfer of AER’s variance relating to the Illinois MPS, in connection with Ameren’s divestiture of New AER to IPH;

• Genco’s request for FERC approval to transfer the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley;

• appeal of the MoPSC’s April 2011 FAC prudence review order and completion of the subsequent FAC prudence reviews;

• Ameren Missouri’s appeal of the MoPSC’s December 2012 electric rate order;

• Ameren Illinois’ appeal of the ICC’s 2012 electric distribution rate orders in its initial and update IEIMA filings;

• A natural gas rate proceeding and an electric distribution formula update filing for Ameren Illinois pending before the ICC;

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

• Entergy’s rehearing request 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 FERC July 2012 order regarding the inclusion of acquisition premiums in Ameren Illinois’ transmission rates;

• ATXI's request for a certificate of public convenience and necessity and project approval from the ICC for the Illinois Rivers project;

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

• remediation matters associated with former 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, Genco, and AERG, created the atmospheric conditions that intensified Hurricane Katrina;

• Ameren Illinois' receipt of tax liability notices relating to prior-period electric and natural gas municipal taxes;

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

• AER’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.

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Required regulatory approvals may not be obtained in connection with Ameren’s divestiture of New AER to IPH or Genco’s sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, and either of those transactions or Medina Valley’s sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to a third-party may not be completed on the anticipated schedule or at all.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. The consummation of the New AER divestiture to IPH is subject to regulatory approvals, including FERC approval and approval of certain license transfers by the FCC. As a condition to IPH’s obligation to complete the transaction, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS. AER’s and Dynegy’s obligation to complete the transaction is also subject to other customary closing conditions.

The consummation of the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers is subject to certain conditions, including the receipt of FERC approval for the sale to Medina Valley and separately for the ultimate sale to any third-party purchaser of these energy centers.

Failure to obtain any of the required regulatory approvals or fulfill any other condition to the closing of these transactions could result in such transaction not being completed on the anticipated schedule or at all.

Ameren has commenced a sale process for the Elgin, Gibson City, and Grand Tower gas-fired energy centers. Ameren may not be able to sell these energy centers at its estimate of fair value or on the time period currently anticipated.

If Ameren’s divestiture of its Merchant Generation business to IPH is not completed as anticipated, Ameren expects to pursue other strategic alternatives to exit that business that may adversely impact Ameren’s results of operations, financial position and liquidity.

If Ameren's divestiture of its Merchant Generation business to IPH is not completed as anticipated, Ameren expects to develop an alternative plan of disposal for that business. Alternative plans of disposal may include the sale of all or parts of the Merchant Generation business and the restructuring of all or a portion of Ameren's equity position in Genco. Ameren's future results of operations, financial position and liquidity may be negatively affected by the impact of, and its ability to successfully execute, any such strategic alternatives, including as a result of long-lived asset impairments, disposal-related losses, contingencies, reduction of existing deferred tax assets, and other consequences that are currently unknown to Ameren.

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
January 1 - January 31, 2013	83,770	$	31.86	—	—
February 1 - February 28, 2013	138,285	33.79		—	—
March 1 - March 31, 2013	—	—		—	—
Total	222,055	$	33.06	—	—

(a) Included in January were 19,369 shares of Ameren common stock purchased by Ameren in open-market transactions pursuant to Ameren's 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren's obligations for Ameren board of directors' compensation awards. The remaining shares of Ameren common stock were purchased by Ameren in open-market transactions pursuant to Ameren's 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren's obligation to distribute shares of common stock for vested performance units. Ameren does not have any publicly announced equity securities repurchase plans or programs.

Ameren Missouri and Ameren Illinois did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from January 1, 2013, to March 31, 2013.

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.

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Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1	Ameren	Transaction Agreement, dated March 14, 2013, between Ameren and IPH	March 19, 2013 Form 8-K, Exhibit 2.1, File No.1-14756
2.2	Ameren	Asset Purchase Agreement, dated March 14, 2013, by and between Medina Valley and Genco	March 19, 2013 Form 8-K, Exhibit 2.2 File No. 1-14756
Material Contracts
10.1	Ameren	Novation and Amendment of Put Option Agreement, dated March 14, 2013, by and among Medina Valley, AERG, Genco and Ameren	March 19, 2013 Form 8-K, Exhibit 10.3, File No. 1-14756
10.2	Ameren	*Employment and Change of Control Agreement, dated March 13, 2013, between Steven R. Sullivan, AER and Ameren	March 19, 2013 Form 8-K, Exhibit 10.4 File No. 1-14756
Statement re: Computation of Ratios
12.1	Ameren	Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.2	Ameren Missouri	Ameren Missouri’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
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
Rule 13a-14(a) / 15d-14(a) Certifications
31.1	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren
31.2	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren
31.3	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Missouri
31.4	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Missouri
31.5	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois
31.6	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois
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
Interactive Data File
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 March 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statement of Income (Loss) for the three months ended March 31, 2013, and 2012, (ii) the Consolidated Statement of Comprehensive Income (Loss) for the three months ended March 31, 2013, and 2012, (iii) the Consolidated Balance Sheet at March 31, 2013, and December 31, 2012, (iv) the Consolidated Statement of Cash Flows for the three months ended March 31, 2013, and 2012, and (v) the Combined Notes to the Financial Statements for the three months ended March 31, 2013. For Ameren Missouri and Ameren Illinois, 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.

Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

UNION ELECTRIC COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

AMEREN ILLINOIS COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

Date: May 10, 2013

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EX-12.1

Exhibit 12.1

Ameren Corporation

Computation of Ratio of Earnings to Fixed Charges

(Thousands of Dollars, Except Ratios)

	Three Months Ended March 31,
	2013 (a)
Earnings available for fixed charges, as defined:
Net income from continuing operations attributable to Ameren Corporation	$	54,023
Tax expense based on income	35,432
Fixed charges excluding preferred stock dividends tax adjustment (b)	108,345
Earnings available for fixed charges, as defined	$	197,800
Fixed charges, as defined:
Interest expense on short-term and long-term debt  (b)	$	99,081
Estimated interest cost within rental expense	1,722
Amortization of net debt premium, discount, and expenses	5,931
Subsidiary preferred stock dividends	1,611
Adjust preferred stock dividends to pretax basis	885
Total fixed charges, as defined	$	109,230
Consolidated ratio of earnings to fixed charges	1.81

(a) Excludes discontinued operations.

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

EX-12.2

Exhibit 12.2

Union Electric Company

Computation of Ratio of Earnings to Fixed Charges and Combined

Fixed Charges and Preferred Stock Dividend Requirements

(Thousands of Dollars, Except Ratios)

	Three Months Ended March 31,
	2013
Earnings available for fixed charges, as defined:
Net income	$	40,350
Tax expense based on income	19,292
Fixed charges (a)	64,006
Earnings available for fixed charges, as defined	$	123,648
Fixed charges, as defined:
Interest expense on short-term and long-term debt  (a)	$	61,329
Estimated interest cost within rental expense	799
Amortization of net debt premium, discount, and expenses	1,878
Total fixed charges, as defined	$	64,006
Ratio of earnings to fixed charges	1.93
Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends	$	855
Adjustment to pretax basis	409
	$	1,264
Combined fixed charges and preferred stock dividend requirements	$	65,270
Ratio of earnings to combined fixed charges and preferred stock dividend requirements	1.89

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

EX-12.3

Exhibit 12.3

Ameren Illinois Company

Computation of Ratio of Earnings to Fixed Charges and Combined

Fixed Charges and Preferred Stock Dividend Requirements

(Thousands of Dollars, Except Ratios)

	Three Months Ended March 31,
	2013
Earnings available for fixed charges, as defined:
Net income	$	31,918
Tax expense based on income	20,086
Fixed charges (a)	32,726
Earnings available for fixed charges, as defined	$	84,730
Fixed charges, as defined:
Interest expense on short-term and long-term debt (a)	$	28,246
Estimated interest cost within rental expense	923
Amortization of net debt premium, discount, and expenses	3,557
Total fixed charges, as defined	$	32,726
Ratio of earnings to fixed charges	2.59
Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends	$	756
Adjustment to pretax basis	476
	$	1,232
Combined fixed charges and preferred stock dividend requirements	$	33,958
Ratio of earnings to combined fixed charges and preferred stock dividend requirements	2.50

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

EX-31.1

Exhibit 31.1

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

OF PRINCIPAL EXECUTIVE OFFICER OF AMEREN CORPORATION

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

I, Thomas R. Voss, certify that:

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2013 of Ameren Corporation;

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

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

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

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

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

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

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

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

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

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

Date: May 10, 2013

 /s/ Thomas R. Voss

Thomas R. Voss

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

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

OF PRINCIPAL FINANCIAL OFFICER OF AMEREN CORPORATION

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

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

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2013 of Ameren Corporation;

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

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

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

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

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

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

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

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

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

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

Date: May 10, 2013

 /s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-31.3

Exhibit 31.3

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

OF PRINCIPAL EXECUTIVE OFFICER OF UNION ELECTRIC COMPANY

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

I, Warner L. Baxter, certify that:

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2013 of Union Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: May 10, 2013

 /s/ Warner L. Baxter

Warner L. Baxter

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

EX-31.4

Exhibit 31.4

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

OF PRINCIPAL FINANCIAL OFFICER OF UNION ELECTRIC COMPANY

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

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

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2013 of Union Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: May 10, 2013

 /s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

EX-31.5

Exhibit 31.5

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

OF PRINCIPAL EXECUTIVE OFFICER OF AMEREN ILLINOIS COMPANY

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

I, Richard J. Mark, certify that:

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2013 of Ameren Illinois Company;

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

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

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

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

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

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

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

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

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

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

Date: May 10, 2013

 /s/ Richard J. Mark

Richard J. Mark

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

EX-31.6

Exhibit 31.6

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

OF PRINCIPAL FINANCIAL OFFICER OF AMEREN ILLINOIS COMPANY

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

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

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2013 of Ameren Illinois Company;

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

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

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

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

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

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

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

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

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

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

Date: May 10, 2013

 /s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.1

Exhibit 32.1

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

AMEREN CORPORATION

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

In connection with the report on Form 10-Q for the quarterly period ended March 31, 2013 of Ameren Corporation (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the "Form 10-Q”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 10, 2013

 
/s/ Thomas R. Voss

Thomas R. Voss

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

 /s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.2

Exhibit 32.2

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

UNION ELECTRIC COMPANY

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

In connection with the report on Form 10-Q for the quarterly period ended March 31, 2013 of Union Electric Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the "Form 10-Q"), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 10, 2013

 /s/ Warner L. Baxter

Warner L. Baxter

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

 /s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.3

Exhibit 32.3

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

AMEREN ILLINOIS COMPANY

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

In connection with the report on Form 10-Q for the quarterly period ended March 31, 2013 of Ameren Illinois Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the "Form 10-Q"), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 10, 2013

 /s/ Richard J. Mark

Richard J. Mark

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

 /s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

XML

Divestiture Transactions and Discontinued Operations (Components of Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Current assets of discontinued operations
Cash and cash equivalents	$ 25		$ 25
Accounts receivable and unbilled revenue	103		102
Materials and supplies	117		134
Mark-to-market derivative assets	101		102
Property and plant, net	607		748
Accumulated deferred income taxes, net	412		373
Other assets	135		116
Total current assets of discontinued operations	1,500		1,600
Current liabilities of discontinued operations
Accounts payable and other current obligations	138		133
Mark-to-market derivative liabilities	82		63
Long-term debt, net	824		824
Asset retirement obligations	86		78
Pension and other postretirement benefits	39		40
Other liabilities	29		28
Total current liabilities of discontinued operations	1,198		1,166
Accumulated other comprehensive gain (loss)	12	[1]	19	[1]
Noncontrolling Interest	$ 8	[2]	$ 8	[2]
Electric Energy, Inc [Member]
Current liabilities of discontinued operations
Percentage of EEI not owned by Ameren	20.00%		20.00%

[1] Accumulated other comprehensive gain related to discontinued operations remains in “Accumulated other comprehensive gain (loss)” on Ameren’s March 31, 2013, and December 31, 2012, balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s balance sheet either before or at the closing of the New AER divestiture.

[2] The 20% ownership interest of EEI not owned by Ameren remains in “Noncontrolling interests” on Ameren’s March 31, 2013, and December 31, 2012, balance sheets. This noncontrolling interest will be removed from Ameren’s balance sheet at the closing of the New AER divestiture.

XML

Derivative Financial Instruments (Potential Loss On Counterparty Exposures) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	$ 16	$ 15
Union Electric Company [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	12	15
Ameren Illinois Company [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	4
Affiliates [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	1
Affiliates [Member] | Union Electric Company [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	1
Commodity Marketing Companies [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	3	1
Commodity Marketing Companies [Member] | Union Electric Company [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	1	1
Commodity Marketing Companies [Member] | Ameren Illinois Company [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	2
Electric Utilities [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	1	1
Electric Utilities [Member] | Union Electric Company [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	1	1
Financial Companies [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	8	10
Financial Companies [Member] | Union Electric Company [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	6	10
Financial Companies [Member] | Ameren Illinois Company [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	2
Municipalities/Cooperatives [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	3	3
Municipalities/Cooperatives [Member] | Union Electric Company [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	$ 3	$ 3

XML

Derivative Financial Instruments (Open Gross Derivative Volumes By Commodity Type) (Detail)	Mar. 31, 2013		Dec. 31, 2012
Coal (In Tons) [Member]
Derivative [Line Items]
Accrual & NPNS Contracts	91,000,000	[1]	96,000,000	[1]
Fuel Oils (In Gallons) [Member]
Derivative [Line Items]
Derivatives That Qualify for Regulatory Deferral	67,000,000	[2],[3]	26,000,000	[2],[3]
Natural Gas (In Mmbtu) [Member]
Derivative [Line Items]
Accrual & NPNS Contracts	15,000,000	[1]	20,000,000	[1]
Other Derivatives	1,000,000	[4]
Derivatives That Qualify for Regulatory Deferral	158,000,000	[2]	147,000,000	[2]
Power (In Megawatt Hours) [Member]
Derivative [Line Items]
Accrual & NPNS Contracts	23,000,000	[1]	24,000,000	[1]
Other Derivatives	2,000,000	[4]	2,000,000	[4]
Derivatives That Qualify for Regulatory Deferral	20,000,000	[2]	23,000,000	[2]
Renewable Energy Credits [Member]
Derivative [Line Items]
Accrual & NPNS Contracts	15,000,000	[1],[5]	15,000,000	[1],[5]
Uranium (Pounds) [Member]
Derivative [Line Items]
Accrual & NPNS Contracts	4,950,000	[1]	5,142,000	[1]
Derivatives That Qualify for Regulatory Deferral	480,000	[2]	446,000	[2]
Union Electric Company [Member] | Natural Gas (In Mmbtu) [Member]
Derivative [Line Items]
Accrual & NPNS Contracts	3,000,000	[1]	4,000,000	[1]
Other Derivatives	1,000,000	[4]
Derivatives That Qualify for Regulatory Deferral	21,000,000	[2]	19,000,000	[2]
Union Electric Company [Member] | Power (In Megawatt Hours) [Member]
Derivative [Line Items]
Accrual & NPNS Contracts	4,000,000	[1]	3,000,000	[1]
Other Derivatives	2,000,000	[4]	2,000,000	[4]
Derivatives That Qualify for Regulatory Deferral	8,000,000	[2]	9,000,000	[2]
Union Electric Company [Member] | Renewable Energy Credits [Member]
Derivative [Line Items]
Accrual & NPNS Contracts	3,000,000	[1],[5]	3,000,000	[1],[5]
Ameren Illinois Company [Member] | Natural Gas (In Mmbtu) [Member]
Derivative [Line Items]
Accrual & NPNS Contracts	12,000,000	[1]	16,000,000	[1]
Derivatives That Qualify for Regulatory Deferral	137,000,000	[2]	128,000,000	[2]
Ameren Illinois Company [Member] | Power (In Megawatt Hours) [Member]
Derivative [Line Items]
Accrual & NPNS Contracts	19,000,000	[1]	21,000,000	[1]
Derivatives That Qualify for Regulatory Deferral	12,000,000	[2]	14,000,000	[2]
Ameren Illinois Company [Member] | Renewable Energy Credits [Member]
Derivative [Line Items]
Accrual & NPNS Contracts	12,000,000	[1],[5]	12,000,000	[1],[5]

[1] Accrual contracts include commodity contracts that do not qualify as derivatives. As of March 31, 2013, these contracts ran through December 2017, March 2015, September 2024, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively.

[2] As of March 31, 2013, these contracts ran through October 2015, March 2017, May 2032, and September 2014 for fuel oils, natural gas, power, and uranium, respectively.

[3] Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.

[4] As of March 31, 2013, these contracts ran through April 2013 and December 2014 for natural gas and power, respectively.

[5] A renewable energy credit is created for every one megawatthour of renewable energy generated. The Ameren Companies’ contracts include renewable energy credits from solar and wind-generated power.

XML

Commitments And Contingencies (Asset Sale) (Details) (Medina Valley Energy Center [Member], USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended
	Feb. 29, 2012	Mar. 31, 2013
Medina Valley Energy Center [Member]
Loss Contingencies [Line Items]
Proceeds from sale of property, plant, and equipment	$ 16
Nontrade Receivables	1
Pretax gain from asset sale	10
Receivable, charge-offs		$ 1

XML

Derivative Financial Instruments (Derivative Instruments With Credit Risk-Related Contingent Features) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Derivative [Line Items]
Aggregate Fair Value of Derivative Liabilities	$ 187	[1]	$ 226	[1]
Cash Collateral Posted	32		61
Potential Aggregate Amount of Additional Collateral Required	140	[2]	155	[2]
Union Electric Company [Member]
Derivative [Line Items]
Aggregate Fair Value of Derivative Liabilities	66	[1]	78	[1]
Cash Collateral Posted	1		3
Potential Aggregate Amount of Additional Collateral Required	62	[2]	71	[2]
Ameren Illinois Company [Member]
Derivative [Line Items]
Aggregate Fair Value of Derivative Liabilities	121	[1]	148	[1]
Cash Collateral Posted	31		58
Potential Aggregate Amount of Additional Collateral Required	$ 78	[2]	$ 84	[2]

[1] Prior to consideration of master trading and netting agreements and including NPNS contract exposures.

[2] 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 determined after consideration of the effects of such agreements.

XML

Long-Term Debt And Equity Financings (Schedule Of Covered Ratio) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Union Electric Company [Member]
Debt Instrument [Line Items]
Bonds Issuable	4,304	[1]
Preferred Stock Issuable	2,454
Retired bond capacity	485
Union Electric Company [Member] | Actual Ratio [Member]
Debt Instrument [Line Items]
Restricted payment interest coverage ratio, Actual	4.7
Dividend Coverage Ratio	128.1
Ameren Illinois Company [Member]
Debt Instrument [Line Items]
Bonds Issuable	3,499	[1],[2]
Preferred Stock Issuable	203
Retired bond capacity	645
Ameren Illinois Company [Member] | Actual Ratio [Member]
Debt Instrument [Line Items]
Restricted payment interest coverage ratio, Actual	7.2
Dividend Coverage Ratio	2.7
Minimum [Member] | Union Electric Company [Member] | Minimum Required Ratio [Member]
Debt Instrument [Line Items]
Restricted payment interest coverage ratio, Actual	2.0	[3]
Dividend Coverage Ratio	2.5	[4]
Minimum [Member] | Ameren Illinois Company [Member] | Minimum Required Ratio [Member]
Debt Instrument [Line Items]
Restricted payment interest coverage ratio, Actual	2.0	[3]
Dividend Coverage Ratio	1.5	[4]

[1] 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.

[2] Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.

[3] 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.

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

XML

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Summary of Nonvested Shares Related To Long-Term Incentive Plan) (Details) (Performance Shares [Member], USD $)	1 Months Ended	3 Months Ended
	Jan. 31, 2013	Mar. 31, 2013
Performance Shares [Member]
Weighted-average Fair Value per Unit at Grant Date
Weighted-average Fair Value per Unit, Nonvested at January 1, 2013	$ 33.56	$ 33.56
Weighted-average Fair Value per Unit, Grants	$ 31.19	$ 31.19	[1]
Weighted-average Fair Value per Unit, Forfeitures		$ 32.67
Weighted-average Fair Value per Unit, Vested		$ 31.19	[2]
Weighted-average Fair Value per Unit, Nonvested at March 31, 2013		$ 32.68
Share Units
Share Units, Nonvested at January 1, 2013	1,192,487	1,192,487
Share Units, Granted		832,034	[1]
Share Units, Forfeitures		(5,456)
Share Units, Vested		(122,671)	[2]
Share Units, Nonvested at March 31, 2013		1,896,394
Performance period		3 years

[1] Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2013 under the 2006 Plan

[2] Share units vested due to the attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period.

XML

Retirement Benefits (Components Of Net Periodic Benefit Cost) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Pension Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 24	$ 21
Interest cost	40	42
Expected return on plan assets	(54)	(52)
Prior service cost (benefit)	(1)	(1)
Actuarial loss	22	19
Net periodic benefit cost	31	29
Postretirement Benefit Costs [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	6	6
Interest cost	12	13
Expected return on plan assets	(16)	(14)
Prior service cost (benefit)	(1)	(1)
Actuarial loss	2	3
Net periodic benefit cost	$ 3	$ 7

XML

Fair Value Measurements (Schedule Of Valuation Process And Unobservable Inputs) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2013		Dec. 31, 2012
Natural Gas [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	3	[1]
Natural Gas [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.20%	[2]
Counterparty credit risk	0.26%	[3],[4]
Nodal basis	(0.18)	[3]
Credit risk	2.00%	[3],[4]
Natural Gas [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.46%	[2]
Counterparty credit risk	5.00%	[3],[4]
Nodal basis	0	[3]
Credit risk	3.00%	[3],[4]
Natural Gas [Member] | Discounted Cash Flow [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.35%	[2]
Counterparty credit risk	1.00%	[3],[4]
Nodal basis	(0.01)	[3]
Credit risk	3.00%	[3],[4]
Natural Gas [Member] | Option Model [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.20%	[2]
Nodal basis	(0.24)	[3]
Natural Gas [Member] | Option Model [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.46%	[2]
Nodal basis	(0.04)	[3]
Natural Gas [Member] | Option Model [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.37%	[2]
Nodal basis	(0.19)	[3]
Natural Gas [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member]
Fair Value Inputs [Abstract]
Credit risk	2.00%	[3],[4]
Natural Gas [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.20%	[2]
Counterparty credit risk	0.26%	[3],[4]
Nodal basis	(0.18)	[3]
Natural Gas [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.46%	[2]
Counterparty credit risk	5.00%	[3],[4]
Nodal basis	(0.02)	[3]
Natural Gas [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.26%	[2]
Counterparty credit risk	1.00%	[3],[4]
Nodal basis	(0.04)	[3]
Natural Gas [Member] | Union Electric Company [Member] | Option Model [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.20%
Nodal basis	(0.24)	[3]
Natural Gas [Member] | Union Electric Company [Member] | Option Model [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.46%
Nodal basis	(0.04)	[3]
Natural Gas [Member] | Union Electric Company [Member] | Option Model [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.37%
Nodal basis	(0.19)	[3]
Natural Gas [Member] | Union Electric Company [Member] | Derivative Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	1	[1]
Natural Gas [Member] | Ameren Illinois Company [Member] | Discounted Cash Flow [Member]
Fair Value Inputs [Abstract]
Credit risk	3.00%	[3],[4]
Natural Gas [Member] | Ameren Illinois Company [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.20%	[2]
Counterparty credit risk	0.70%	[3]
Nodal basis	(0.05)	[3]
Natural Gas [Member] | Ameren Illinois Company [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.46%	[2]
Counterparty credit risk	2.00%	[3]
Nodal basis	0	[3]
Natural Gas [Member] | Ameren Illinois Company [Member] | Discounted Cash Flow [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.33%	[2]
Counterparty credit risk	1.00%	[3]
Nodal basis	0	[3]
Natural Gas [Member] | Ameren Illinois Company [Member] | Derivative Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	2	[1]
Natural Gas [Member] | Derivative Liabilities [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(1)	[1]
Natural Gas [Member] | Derivative Liabilities [Member] | Union Electric Company [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(1)	[1]
Natural Gas [Member] | Derivative Liabilities [Member] | Ameren Illinois Company [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities		[1]
Fuel Oils [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	7	[1]	8	[1]
Fuel Oils [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.20%	[2]	0.21%	[2]
Counterparty credit risk	0.26%	[3],[4]	0.12%	[3],[4]
Credit risk			2.00%	[3],[4]
Fuel Oils [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.59%	[2]	0.60%	[2]
Counterparty credit risk	3.00%	[3],[4]	1.00%	[3],[4]
Fuel Oils [Member] | Discounted Cash Flow [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.39%	[2]	0.44%	[2]
Counterparty credit risk	1.00%	[3],[4]	1.00%	[3],[4]
Fuel Oils [Member] | Option Model [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Volatalities	10.00%	[2]	7.00%	[2]
Fuel Oils [Member] | Option Model [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Volatalities	19.00%	[2]	27.00%	[2]
Fuel Oils [Member] | Option Model [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Volatalities	17.00%	[2]	24.00%	[2]
Fuel Oils [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member]
Fair Value Inputs [Abstract]
Credit risk			2.00%	[3],[4]
Fuel Oils [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.20%	[2]	0.21%	[2]
Counterparty credit risk	0.26%	[3],[4]	0.12%	[3],[4]
Fuel Oils [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.59%	[2]	0.60%	[2]
Counterparty credit risk	3.00%	[3],[4]	1.00%	[3],[4]
Fuel Oils [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.39%	[2]	0.44%	[2]
Counterparty credit risk	1.00%	[3],[4]	1.00%	[3],[4]
Fuel Oils [Member] | Union Electric Company [Member] | Option Model [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Volatalities	10.00%	[2]	7.00%	[2]
Fuel Oils [Member] | Union Electric Company [Member] | Option Model [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Volatalities	19.00%	[2]	27.00%	[2]
Fuel Oils [Member] | Union Electric Company [Member] | Option Model [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Volatalities	17.00%	[2]	24.00%	[2]
Fuel Oils [Member] | Union Electric Company [Member] | Derivative Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	7	[1]	8	[1]
Fuel Oils [Member] | Derivative Liabilities [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(2)	[1]	(3)	[1]
Fuel Oils [Member] | Derivative Liabilities [Member] | Union Electric Company [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(2)	[1]	(3)	[1]
Power [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Counterparty credit risk	0.22%	[3],[4]	0.22%	[3],[4]
Nodal basis	(5)	[3]	(5)	[3]
Credit risk	2.00%	[3],[4]	2.00%	[3],[4]
Average bid/ask consensus peak and offpeak pricing	24	[3]	22	[3]
Estimated auction price	0	[2]	(281)	[2]
Power [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Counterparty credit risk	5.00%	[3],[4]	1.00%	[3],[4]
Nodal basis	(1)	[3]	(1)	[3]
Credit risk	3.00%	[3],[4]	5.00%	[3],[4]
Average bid/ask consensus peak and offpeak pricing	48	[3]	47	[3]
Estimated auction price	4,280	[2]	1,851	[2]
Power [Member] | Discounted Cash Flow [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Counterparty credit risk	2.00%	[3],[4]	1.00%	[3],[4]
Nodal basis	(3)	[3]	(3)	[3]
Credit risk	3.00%	[3],[4]	5.00%	[3],[4]
Average bid/ask consensus peak and offpeak pricing	33	[3]	31	[3]
Estimated auction price	190	[2]	178	[2]
Power [Member] | Fundamental Energy Production Model [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Estimated future gas prices	5	[2]	4	[2]
Power [Member] | Fundamental Energy Production Model [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Estimated future gas prices	7	[2]	8	[2]
Power [Member] | Fundamental Energy Production Model [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Estimated future gas prices	6	[2]	6	[2]
Power [Member] | Contract Price Allocation [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	5	[4]	5	[2]
Power [Member] | Contract Price Allocation [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	7	[4]	7	[2]
Power [Member] | Contract Price Allocation [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	6	[4]	6	[2]
Power [Member] | Derivative Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	12	[1],[5]	14	[1],[5]
Power [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member]
Fair Value Inputs [Abstract]
Credit risk	2.00%	[3],[4]	2.00%	[3],[4]
Power [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Counterparty credit risk	0.22%	[3],[4]	0.22%	[3],[4]
Nodal basis	(5)	[3]	(5)	[3]
Average bid/ask consensus peak and offpeak pricing	24	[3]	24	[3]
Estimated auction price	0	[2]	(281)	[2]
Power [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Counterparty credit risk	5.00%	[3],[4]	1.00%	[3],[4]
Nodal basis	(1)	[3]	(1)	[3]
Average bid/ask consensus peak and offpeak pricing	51	[3]	56	[3]
Estimated auction price	4,280	[2]	1,851	[2]
Power [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Counterparty credit risk	1.00%	[3],[4]	1.00%	[3],[4]
Nodal basis	(3)	[3]	(2)	[3]
Average bid/ask consensus peak and offpeak pricing	38	[3]	36	[3]
Estimated auction price	190	[2]	178	[2]
Power [Member] | Union Electric Company [Member] | Derivative Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	9	[1],[5]	14	[1],[5]
Power [Member] | Ameren Illinois Company [Member] | Discounted Cash Flow [Member]
Fair Value Inputs [Abstract]
Counterparty credit risk	2.00%	[3],[4]	5.00%	[3],[4]
Credit risk	3.00%	[3],[4]
Power [Member] | Ameren Illinois Company [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Nodal basis	(4)	[2]	(5)	[2]
Average bid/ask consensus peak and offpeak pricing	24	[2]	22	[2]
Power [Member] | Ameren Illinois Company [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Nodal basis	(1)	[2]	(1)	[2]
Average bid/ask consensus peak and offpeak pricing	42	[2]	47	[2]
Power [Member] | Ameren Illinois Company [Member] | Discounted Cash Flow [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Nodal basis	(3)	[2]	(3)	[2]
Average bid/ask consensus peak and offpeak pricing	32	[2]	30	[2]
Power [Member] | Ameren Illinois Company [Member] | Fundamental Energy Production Model [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Estimated future gas prices	5	[2]	4	[2]
Power [Member] | Ameren Illinois Company [Member] | Fundamental Energy Production Model [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Estimated future gas prices	7	[2]	8	[2]
Power [Member] | Ameren Illinois Company [Member] | Fundamental Energy Production Model [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Estimated future gas prices	6	[2]	6	[2]
Power [Member] | Ameren Illinois Company [Member] | Contract Price Allocation [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	5	[2]	5	[2]
Power [Member] | Ameren Illinois Company [Member] | Contract Price Allocation [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	7	[2]	7	[2]
Power [Member] | Ameren Illinois Company [Member] | Contract Price Allocation [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	6	[2]	6	[2]
Power [Member] | Ameren Illinois Company [Member] | Derivative Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	3	[1],[5]	0	[1],[5]
Power [Member] | Derivative Liabilities [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(91)	[1],[5]	(114)	[1],[5]
Power [Member] | Derivative Liabilities [Member] | Union Electric Company [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(7)	[1],[5]	(3)	[1],[5]
Power [Member] | Derivative Liabilities [Member] | Ameren Illinois Company [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(84)	[1],[5]	(111)	[1],[5]
Uranium [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Average bid/ask consensus pricing	42	[2]	43	[2]
Uranium [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Average bid/ask consensus pricing	45	[2]	46	[2]
Uranium [Member] | Discounted Cash Flow [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Average bid/ask consensus pricing	43	[2]	44	[2]
Uranium [Member] | Derivative Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets		[1]		[1]
Uranium [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Average bid/ask consensus pricing	42	[2]	43	[2]
Uranium [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Average bid/ask consensus pricing	45	[2]	46	[2]
Uranium [Member] | Union Electric Company [Member] | Discounted Cash Flow [Member] | Weighted Average [Member]
Fair Value Inputs [Abstract]
Average bid/ask consensus pricing	43	[2]	44	[2]
Uranium [Member] | Union Electric Company [Member] | Derivative Assets [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets		[1]		[1]
Uranium [Member] | Derivative Liabilities [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(2)	[1]	(2)	[1]
Uranium [Member] | Derivative Liabilities [Member] | Union Electric Company [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(2)	[1]	(2)	[1]

[1] The derivative asset and liability balances are presented net of counterparty credit considerations.

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

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

[4] Counterparty credit risk is only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri, and Ameren Illinois credit risk is only applied to counterparties with derivative liability balances.

[5] Power valuations utilize visible third party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand.

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Segment Information (Schedule Of Segment Reporting Information By Segment) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012	Dec. 31, 2012
Segment Reporting Information [Line Items]
External revenues	$ 1,475		$ 1,412
Continuing Operations	54		37
Net income (loss) attributable to Ameren Corporation	(145)		(403)
Total assets	21,952			22,209
Union Electric Company [Member]
Segment Reporting Information [Line Items]
External revenues	789		686
Intersegment revenues	7		5
Continuing Operations	40		21
Total assets	12,867			13,043
Ameren Illinois Company [Member]
Segment Reporting Information [Line Items]
External revenues	684		724
Intersegment revenues	0		0
Continuing Operations	31		27
Total assets	7,288			7,282
Other Segment [Member]
Segment Reporting Information [Line Items]
External revenues	2		2
Intersegment revenues	2		1
Continuing Operations	(17)		(11)
Total assets	1,289			1,228
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
External revenues	0		0
Intersegment revenues	(9)		(6)
Total assets	(992)			(944)
Segment, Continuing Operations [Member]
Segment Reporting Information [Line Items]
External revenues	1,475		1,412
Continuing Operations	54		37
Total assets	$ 20,452	[1]		$ 20,609	[1]

[1] Excludes “Current assets of discontinued operations.” See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

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Callaway Energy Center (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2013 mill	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Nuclear Waste Matters [Line Items]
Number of mills charged for NWF fee	1
Settlement payment	$ 6
Annual decommissioning costs included in costs of service		$ 7	$ 7	$ 7
Missouri Public Service Commission, Requirement to File Updated Cost Study and Funding Analysis for Decommissioning Energy Center, Period	3 years
Nuclear Plant [Member]
Nuclear Waste Matters [Line Items]
Assumed life of plant, in years	40 years

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Other Income and Expenses (Tables)

3 Months Ended

Mar. 31, 2013

Other Nonoperating Income (Expense) [Abstract]

Other Income And Expenses

	Three Months
	2013		2012
Ameren:(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	8	$	9
Interest income on industrial development revenue bonds	7		7
Other	—		1
Total miscellaneous income	$	15	$	17
Miscellaneous expense:
Donations	$	4	$	12	(b)
Other	4		3
Total miscellaneous expense	$	8	$	15
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	7	$	8
Interest income on industrial development revenue bonds	7		7
Total miscellaneous income	$	14	$	15
Miscellaneous expense:
Donations	$	2	$	2
Other	3		1
Total miscellaneous expense	$	5	$	3
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	1	$	1
Total miscellaneous income	$	1	$	1
Miscellaneous expense:
Donations	$	3	$	10	(b)
Other	—		1
Total miscellaneous expense	$	3	$	11

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

(b) Includes Ameren Illinois’ one-time $7.5 million donation to the Illinois Science and Energy Innovation Trust pursuant to the IEIMA as a result of Ameren Illinois’ 2012 participation in the formula ratemaking process.

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Derivative Financial Instruments (Cumulative Amount Of Pretax Net Gains (Losses) On All Derivative Instruments In OCI) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Derivative [Line Items]
Current gains deferred as regulatory liabilities	$ 135		$ 100
Current losses deferred as regulatory assets	196		247
Fuel Oils [Member]
Derivative [Line Items]
Current gains deferred as regulatory liabilities	4
Current losses deferred as regulatory assets	1
Fuel Oils [Member] | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	4	[1]	4	[1]
Natural Gas [Member]
Derivative [Line Items]
Current gains deferred as regulatory liabilities	6
Current losses deferred as regulatory assets	45
Natural Gas [Member] | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(71)	[2]	(107)	[2]
Power [Member]
Derivative [Line Items]
Current gains deferred as regulatory liabilities	12
Current losses deferred as regulatory assets	21
Power [Member] | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(79)	[3]	(99)	[3]
Uranium [Member]
Derivative [Line Items]
Current losses deferred as regulatory assets	2
Uranium [Member] | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(2)	[4]	(2)	[4]
Union Electric Company [Member]
Derivative [Line Items]
Current gains deferred as regulatory liabilities	23		18
Current losses deferred as regulatory assets	144		163
Union Electric Company [Member] | Fuel Oils [Member]
Derivative [Line Items]
Current gains deferred as regulatory liabilities	4
Current losses deferred as regulatory assets	1
Union Electric Company [Member] | Fuel Oils [Member] | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	4	[1]	4	[1]
Union Electric Company [Member] | Natural Gas [Member]
Derivative [Line Items]
Current gains deferred as regulatory liabilities	1
Current losses deferred as regulatory assets	7
Union Electric Company [Member] | Natural Gas [Member] | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(10)	[2]	(14)	[2]
Union Electric Company [Member] | Power [Member]
Derivative [Line Items]
Current gains deferred as regulatory liabilities	12
Current losses deferred as regulatory assets	10
Union Electric Company [Member] | Power [Member] | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	2	[3]	12	[3]
Union Electric Company [Member] | Uranium [Member]
Derivative [Line Items]
Current losses deferred as regulatory assets	2
Union Electric Company [Member] | Uranium [Member] | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(2)	[4]	(2)	[4]
Ameren Illinois Company [Member]
Derivative [Line Items]
Current gains deferred as regulatory liabilities	113		82
Current losses deferred as regulatory assets	52		84
Ameren Illinois Company [Member] | Natural Gas [Member]
Derivative [Line Items]
Current gains deferred as regulatory liabilities	5
Current losses deferred as regulatory assets	38
Ameren Illinois Company [Member] | Natural Gas [Member] | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(61)	[2]	(93)	[2]
Ameren Illinois Company [Member] | Power [Member]
Derivative [Line Items]
Current losses deferred as regulatory assets	11
Ameren Illinois Company [Member] | Power [Member] | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	$ (81)	[3]	$ (111)	[3]

[1] 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 March 31, 2013. Current gains deferred as regulatory liabilities include $4 million and $4 million at Ameren and Ameren Missouri as of March 31, 2013, respectively. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of March 31, 2013, respectively.

[2] 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 March 31, 2013. Current gains deferred as regulatory liabilities include $6 million, $1 million, and $5 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2013. Current losses deferred as regulatory assets include $45 million, $7 million, and $38 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2013.

[3] Represents net gains (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 March 31, 2013. Current gains deferred as regulatory liabilities include $12 million and $12 million at Ameren and Ameren Missouri, respectively, as of March 31, 2013. Current losses deferred as regulatory assets include $21 million, $10 million, and $11 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2013.

[4] 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 March 31, 2013. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri as of March 31, 2013, respectively.

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Rate And Regulatory Matters (Narrative-Illinois) (Detail) (Ameren Illinois Company [Member], USD $) In Millions, unless otherwise specified		12 Months Ended	0 Months Ended
	Dec. 31, 2012 Ieima [Member] Electric Distribution [Member] Final Rate Order [Member]	Dec. 31, 2012 Illinois Commerce Commission [Member]	Apr. 19, 2013 Illinois Commerce Commission [Member] Subsequent Event [Member]	Dec. 31, 2012 Revenue Subject to Refund [Member] Illinois Commerce Commission [Member]
Rate And Regulatory Matters [Line Items]
Revenue requirement	$ 765		$ 785
Requested rate decrease, amount			30
Regulatory liability				50
Approved rate increase, amount		$ 20

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Segment Information (Narrative) (Detail)	3 Months Ended
	Mar. 31, 2013 Segment
Segment Reporting [Abstract]
Number of reportable segments	3

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Divestiture Transactions and Discontinued Operations (Narrative) (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended	3 Months Ended
	Mar. 14, 2013	Mar. 31, 2013 center	Dec. 31, 2012
New Ameren Energy Resources Company, LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of assets to be disposed of		$ 155
Discontinued operations deferred tax liability		98
Discontinued operations deferred tax asset		63
Number of energy centers impaired		3
Disposal group, fair value			133
Obligation to provide credit support, period	24 months
Buyer's indemnification guarantee obligation	25
Buyer's indemnification guarantee obligation, period	24 months
Period for working capital adjustment	120 days
Transitional services to be provided to buyer, period	6 months
Transitional services to be provided to buyer at no charge, period	90 days
Transitional services to be provided to buyer at no charge, maximum amount	5
Transitional services to be provided to buyer, additional period	6 months
Meredosia and Hutsonville Energy Centers [Member] | Ameren Energy Generating Company [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset retirement obligation		27
Notes Payable, Other Payables [Member] | New Ameren Energy Resources Company, LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Converted instrument, period for conversion	24 months
Senior Notes [Member] | Ameren Energy Generating Company [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Aggregate principal amount of senior notes		825
Illinois Power Holdings, LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Pension and other postretirement obligations assumed by counterparty		39
Defined benefit plan assets assumed by counterparty		15
Transaction agreement, cash retained by counterparty		85
Elgin, Gibson City and Grand Tower Energy Centers [Member] | Ameren Energy Generating Company [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of property, plant, and equipment	100
Expected additional proceeds from sale of assets, minimum	33
Expected proceeds from sale of assets, minimum	$ 133
Maximum [Member] | New Ameren Energy Resources Company, LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Transitional services to be provided to buyer, period	12 months

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Derivative Financial Instruments (Maximum Exposure If Counterparties Fail To Perform On Contracts) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	$ 24	$ 23
Union Electric Company [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	16	22
Ameren Illinois Company [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	8	1
Affiliates [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	1
Affiliates [Member] | Union Electric Company [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	1
Commodity Marketing Companies [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	3	2
Commodity Marketing Companies [Member] | Union Electric Company [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	1	2
Commodity Marketing Companies [Member] | Ameren Illinois Company [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	2
Electric Utilities [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	1	3
Electric Utilities [Member] | Union Electric Company [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	1	3
Financial Companies [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	14	15
Financial Companies [Member] | Union Electric Company [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	10	14
Financial Companies [Member] | Ameren Illinois Company [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	4	1
Municipalities/Cooperatives [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	3	3
Municipalities/Cooperatives [Member] | Union Electric Company [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	3	3
Oil And Gas Companies [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	2
Oil And Gas Companies [Member] | Ameren Illinois Company [Member]
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	$ 2

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Commitments And Contingencies (Environmental Matters) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013 State
Minimum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	395	[1]
Maximum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	480	[1]
Estimated Capital Costs 2012 [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	35	[1]
Estimated Capital Costs 2014 to 2017 [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	120	[1]
Estimated Capital Costs 2014 to 2017 [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	150	[1]
Estimated Capital Costs 2018 to 2022 [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	240	[1]
Estimated Capital Costs 2018 to 2022 [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	295	[1]
Ameren Energy Generating Company [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	350	[2]
Ameren Energy Generating Company [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	425	[2]
Ameren Energy Generating Company [Member] | Estimated Capital Costs 2012 [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	30	[2]
Ameren Energy Generating Company [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	100	[2]
Ameren Energy Generating Company [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	125	[2]
Ameren Energy Generating Company [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	220	[2]
Ameren Energy Generating Company [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	270	[2]
Union Electric Company [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	1,115	[3]
Union Electric Company [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	1,340	[3]
Union Electric Company [Member] | Estimated Capital Costs 2012 [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	105	[3]
Union Electric Company [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	215	[3]
Union Electric Company [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	260	[3]
Union Electric Company [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	795	[3]
Union Electric Company [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	975	[3]
AERG [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	45
AERG [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	55
AERG [Member] | Estimated Capital Costs 2012 [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	5
AERG [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	20
AERG [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	25
AERG [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	20
AERG [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state environmental regulations	25
CAIR [Member]
Loss Contingencies [Line Items]
Number of states participating in the cap-and-trade program	28
MATS [Member]
Loss Contingencies [Line Items]
Percent of top performing facilities	12.00%
Former Coal Tar Distillery [Member] | Union Electric Company [Member]
Loss Contingencies [Line Items]
Loss contingency range of possible loss minimum	2.0
Loss contingency range of possible loss maximum	5.0
Accrual for environmental loss contingencies	2.0
Former Coal Ash Landfill [Member] | Ameren Illinois Company [Member]
Loss Contingencies [Line Items]
Loss contingency range of possible loss minimum	0.5
Loss contingency range of possible loss maximum	6.0
Accrual for environmental loss contingencies	0.5
Newton Energy Center Scrubbers [Member] | Ameren Energy Generating Company [Member] | Newton Energy Center Estimated Capital Costs 2013 to 2017 [Member]
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	20
Manufactured Gas Plant [Member]
Loss Contingencies [Line Items]
Loss contingency range of possible loss minimum	259.0
Loss contingency range of possible loss maximum	342.0
Accrual for environmental loss contingencies	259.0	[4]
Manufactured Gas Plant [Member] | Union Electric Company [Member]
Loss Contingencies [Line Items]
Loss contingency range of possible loss minimum	5.0
Loss contingency range of possible loss maximum	6.0
Accrual for environmental loss contingencies	5.0	[4]
Manufactured Gas Plant [Member] | Ameren Illinois Company [Member]
Loss Contingencies [Line Items]
Number of remediation sites	44
Loss contingency range of possible loss minimum	254.0
Loss contingency range of possible loss maximum	336.0
Accrual for environmental loss contingencies	254.0	[4]
Other Environmental [Member] | Ameren Illinois Company [Member]
Loss Contingencies [Line Items]
Accrual for environmental loss contingencies	0.8
Sauget Area Two [Member] | Union Electric Company [Member]
Loss Contingencies [Line Items]
Loss contingency range of possible loss minimum	0.3
Loss contingency range of possible loss maximum	10.0
Accrual for environmental loss contingencies	0.3
Substation in St Charles, Missouri [Member] | Union Electric Company [Member]
Loss Contingencies [Line Items]
Loss contingency range of possible loss minimum	1.7
Loss contingency range of possible loss maximum	4.5
Accrual for environmental loss contingencies	1.7

[1] Assumes the Merchant Generation facilities are owned by Ameren.

[2] ncludes estimated costs of approximately $20 million annually, excluding capitalized interest, from 2013 through 2017 for construction of two Newton energy center scrubbers.

[3] Ameren Missouri’s expenditures are expected to be recoverable from ratepayers.

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

XML

Fair Value Measurements (Schedule Of Transfers Between Fair Value Hierarchy Levels) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Derivative [Line Items]
Net fair value of Level 3 transfers	$ (1)	$ 186
Fuel Oils [Member]
Derivative [Line Items]
Assets Transfers into Level 3		2
Fuel Oils [Member] | Transfer Into/Out of Level 1 [Member]
Derivative [Line Items]
Assets Transfers into Level 3		2
Natural Gas [Member]
Derivative [Line Items]
Assets Transfers out of Level 3		185
Natural Gas [Member] | Transfer Into/Out of Level 2 [Member]
Derivative [Line Items]
Assets Transfers out of Level 3		185
Power [Member]
Derivative [Line Items]
Assets Transfers into Level 3	(2)
Assets Transfers out of Level 3	1	(1)	[1]
Power [Member] | Transfer Into/Out of Level 2 [Member]
Derivative [Line Items]
Assets Transfers into Level 3	(2)
Assets Transfers out of Level 3	1	(1)
Union Electric Company [Member]
Derivative [Line Items]
Net fair value of Level 3 transfers	(1)	16
Union Electric Company [Member] | Fuel Oils [Member]
Derivative [Line Items]
Assets Transfers into Level 3		2
Union Electric Company [Member] | Fuel Oils [Member] | Transfer Into/Out of Level 1 [Member]
Derivative [Line Items]
Assets Transfers into Level 3		2
Union Electric Company [Member] | Natural Gas [Member]
Derivative [Line Items]
Assets Transfers out of Level 3		15
Union Electric Company [Member] | Natural Gas [Member] | Transfer Into/Out of Level 2 [Member]
Derivative [Line Items]
Assets Transfers out of Level 3		15
Union Electric Company [Member] | Power [Member]
Derivative [Line Items]
Assets Transfers into Level 3	(2)
Assets Transfers out of Level 3	1	(1)	[1]
Union Electric Company [Member] | Power [Member] | Transfer Into/Out of Level 2 [Member]
Derivative [Line Items]
Assets Transfers into Level 3	(2)
Assets Transfers out of Level 3	1	(1)
Ameren Illinois Company [Member] | Natural Gas [Member]
Derivative [Line Items]
Assets Transfers out of Level 3		170
Ameren Illinois Company [Member] | Natural Gas [Member] | Transfer Into/Out of Level 2 [Member]
Derivative [Line Items]
Assets Transfers out of Level 3		170
Ameren Illinois Company [Member] | Power [Member]
Derivative [Line Items]
Assets Transfers into Level 3
Assets Transfers out of Level 3			[1]

[1] Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company.

XML

Other Income and Expenses (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Other Nonoperating Income (Expense) [Line Items]
Allowance for equity funds used during construction	$ 8	[1]	$ 9	[1]
Interest income on industrial development revenue bonds	7	[1]	7	[1]
Other	0	[1]	1	[1]
Total miscellaneous income	15	[1]	17	[1]
Donations	4.0	[1]	12.0	[1],[2]
Other	4	[1]	3	[1]
Total miscellaneous expense	8	[1]	15	[1]
Union Electric Company [Member]
Other Nonoperating Income (Expense) [Line Items]
Allowance for equity funds used during construction	7		8
Interest income on industrial development revenue bonds	7		7
Total miscellaneous income	14		15
Donations	2.0		2.0
Other	3		1
Total miscellaneous expense	5		3
Ameren Illinois Company [Member]
Other Nonoperating Income (Expense) [Line Items]
Allowance for equity funds used during construction	1		1
Total miscellaneous income	1		1
Donations	3.0		10.0	[2]
Other	0		1
Total miscellaneous expense	3		11
Ameren Illinois Company [Member] | One-Time Donation [Member] | Illinois Science And Energy Innovation Trust [Member]
Other Nonoperating Income (Expense) [Line Items]
Donations	$ 7.5

[1] Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

[2] Includes Ameren Illinois’ one-time $7.5 million donation to the Illinois Science and Energy Innovation Trust pursuant to the IEIMA as a result of Ameren Illinois’ 2012 participation in the formula ratemaking process.

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Divestiture Transactions and Discontinued Operations (Notes)

3 Months Ended

Mar. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS

DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS

Transaction Agreement with IPH

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Under the terms of the transaction agreement, AER will effect a reorganization that will, among other things, transfer substantially all of the assets and liabilities of AER, other than (i) any outstanding debt obligations of AER to Ameren or its other subsidiaries, except for certain intercompany balances discussed below, (ii) all of the issued and outstanding equity interests in Medina Valley, which were distributed to Ameren in March 2013, (iii) the assets and liabilities associated with Genco’s Meredosia, Hutsonville, Elgin, Gibson City, and Grand Tower energy centers, (iv) the obligations relating to Ameren's single-employer pension and postretirement benefit plans, and (v) the deferred tax positions associated with Ameren's ownership of these retained assets and liabilities, to New AER. IPH will acquire all of the equity interests in New AER.

Ameren will retain the pension and postretirement benefit obligations associated with current and former employees of AER that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan. This noncurrent obligation is reflected on Ameren’s consolidated balance sheet as “Pension and other postretirement benefits.” IPH will assume the pension and other postretirement benefit obligations associated with EEI’s current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. The obligations to be assumed by IPH are estimated at $39 million at March 31, 2013. IPH will also acquire the estimated $15 million asset at March 31, 2013, relating to the overfunded status of one of EEI’s postretirement plans.

Ameren will retain Genco’s Meredosia and Hutsonville energy centers, which are no longer in operation and had an immaterial property and plant asset balance as of March 31, 2013. Ameren will also retain AROs associated with these energy centers, estimated at $27 million as of March 31, 2013. All other AROs associated with AER will be assumed by either IPH or the third-party buyer of the Grand Tower energy center. Upon the transaction agreement closing, with the exception of certain agreements, such as supply obligations to Ameren Illinois, a note from New AER to Ameren relating to cash collateral that will remain outstanding at closing, and Genco money pool advances, all intercompany agreements and debt between AER and its subsidiaries, on the one hand, and Ameren and its affiliates, on the other hand, will be either retained or cancelled by Ameren, without any cost or obligation to IPH or New AER and its subsidiaries. Immediately prior to the transaction agreement closing, the cash collateral provided to New AER by Ameren through money pool borrowings will be converted to a note payable to Ameren which will be payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced.

Genco's $825 million in aggregate principal amount of senior notes will remain outstanding following the transaction agreement closing and will continue to be solely obligations of Genco. Pursuant to the transaction agreement, in addition to the cash paid to Genco for the Elgin, Gibson City, and Grand Tower energy center sale, Ameren will cause $85 million of cash to be retained at New AER.

As a condition to the transaction agreement, Genco exercised the amended put option agreement for the sale of the Elgin, Gibson City and Grand Tower gas-fired energy centers to Medina Valley. Ameren has commenced a sale process for these three energy centers and expects a third-party sale will be completed during 2013.

Completion of the New AER sale to IPH is subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC. On April 16, 2013, AER and Dynegy filed with FERC an application for approval of the divestiture of New AER and Genco’s sale of the Elgin, Gibson City and Grand Tower gas-fired energy centers to Medina Valley. As a condition to IPH’s obligation to complete the transaction, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS. AER and Dynegy filed a transfer request with the Illinois Pollution Control Board on May 2, 2013. Ameren’s and IPH’s obligation to complete the transaction is also subject to other customary closing conditions, including the material accuracy of each company’s representations and warranties and the compliance, in all material respects, with each company’s covenants. The transaction agreement contains customary representations and warranties of Ameren and IPH, including representations and warranties of Ameren with respect to the business being sold. The transaction agreement also contains customary covenants of Ameren and IPH, including the covenant of Ameren that AER will be operated in the ordinary course prior to the closing.

Ameren expects the closing of the New AER divestiture to IPH will occur in the fourth quarter of 2013. If the closing does not occur on or before March 14, 2014, subject to a one-month extension to obtain FERC approval, either party may elect to terminate the transaction agreement if the inability to close the transaction by such date is not the result of the failure of the terminating company to fulfill any of its obligations under the transaction agreement.

Amended Put Option Agreement, Asset Purchase Agreement and Guaranty

See Note 9 - Related Party Transactions for additional information regarding the original put option agreement between Genco and AERG that was entered into on March 28, 2012.

Prior to entry into the transaction agreement with IPH as discussed above, (i) the original put option agreement between Genco and AERG was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley and (ii) Genco exercised its option under the amended put option agreement to sell the Elgin, Gibson City and Grand Tower gas-fired energy centers to Medina Valley. As a result, on March 14, 2013, Genco received an initial payment of $100 million in accordance with the terms of the amended put option agreement. Genco advanced the initial payment amount it received into the non-state-regulated subsidiaries money pool. In connection with the amended put option agreement, Ameren's guaranty, dated March 28, 2012, was modified to replace all references to AERG with references to Medina Valley.

Pursuant to the amended put option agreement, Genco and Medina Valley entered into an asset purchase agreement, dated March 14, 2013. Genco and Medina Valley have engaged three appraisers to conduct a fair market valuation of the Elgin, Gibson City and Grand Tower gas-fired energy centers, which valuations will be averaged and subject to adjustment at the closing of the asset purchase agreement to reflect the assets and liabilities associated with the Elgin, Gibson City and Grand Tower gas-fired energy centers. At the asset purchase agreement closing, Genco will receive an additional amount equal to the greater of (i) $33 million, or (ii) the appraised value of the Elgin, Gibson City and Grand Tower gas-fired energy centers less the initial payment of $100 million, for a total purchase price of at least $133 million, and Genco will sell and transfer to Medina Valley all of its rights in the Elgin, Gibson City and Grand Tower gas-fired energy centers as a condition to the transaction agreement. If these gas-fired energy centers are subsequently sold by Medina Valley within two years of the asset purchase agreement closing, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the amounts previously paid to Genco. Ameren has commenced a sale process for these three energy centers and expects a third-party sale will be completed during 2013. Should FERC approval not be obtained and the transfer of the Elgin, Gibson City, and Grand Tower energy centers cannot be completed, Genco will be required to return to Medina Valley the initial payment received in March 2013.

The asset purchase agreement contains customary representations, warranties and covenants of Genco and Medina Valley. The consummation of the transactions contemplated by the asset purchase agreement is subject to certain conditions, including the receipt of FERC approval and other customary conditions.

Discontinued Operations Presentation

As of March 14, 2013, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation and, therefore, were classified separately in Ameren’s consolidated financial statements as discontinued operations for all periods presented in this report. Ameren concluded that New AER and collectively the Elgin, Gibson City, and Grand Tower gas-fired energy centers are two separate disposal groups. Both disposal groups have been aggregated in the disclosures below. Each disposal group was measured at fair value on a nonrecurring basis with inputs that are classified as Level 3 within the fair value hierarchy.

The following table presents the components of discontinued operations in Ameren's consolidated statement of income (loss) for the three months ended March 31, 2013, and 2012:

	Three Months
	2013				2012
Operating revenues	$	264			$	246
Operating expenses	(415		)	(a)	(826		)	(b)
Operating (loss)	(151		)		(580		)
Other income (loss)	(2		)		—
Interest charges	(11		)		(15		)
Loss before income taxes	(164		)		(595		)
Income tax (expense) benefit	(35		)		153
Loss from discontinued operations, net of taxes	$	(199	)		$	(442	)

(a) Includes a noncash pretax impairment charge of $155 million to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell.

(b) Includes 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 under held and used accounting guidance.

As the New AER disposal group met the discontinued operations criteria at March 31, 2013, Ameren evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value of the disposal group, less cost to sell. The fair value was based on the terms of Ameren’s agreement to divest New AER to IPH. Ameren will receive no cash proceeds from IPH for the divestiture of New AER. Ameren recorded a pretax charge to earnings of $155 million for the three months ended March 31, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. The impairment loss was recorded in “Operating expenses” within the components of the discontinued operations statement of income (loss) with a corresponding reduction in “Property and Plant, net” within the components of the discontinued operations balance sheet. Ameren estimated the impairment loss of the disposal group based on the estimated fair value pursuant to the terms of the transaction agreement with IPH, using information currently available, and assuming an expected fourth quarter 2013 closing. Actual operating results, derivative market values, capital expenditures and other items will impact the ultimate loss recognized to reduce the carrying value of the New AER disposal group to its actual fair value less cost to sell, which will be recorded in discontinued operations after all of the information becomes available. In addition, any curtailment gain related to Ameren's pension and postretirement plans will be recorded when the related employees terminate employment with Ameren. The ultimate impairment loss may differ materially from the estimated loss recorded in the first quarter of 2013.

Ameren recognized the excess of the tax basis over the financial reporting basis of its stock investment in AER when it became apparent, in the three months ended March 31, 2013, that the temporary difference would reverse. This change in basis resulted in a discontinued operations deferred tax expense of $98 million, which was partially offset by the expected tax benefits of $63 million related to the pretax loss from discontinued operations including the impairment charge recorded in the first quarter of 2013. The final tax basis of the AER disposal group and the related tax benefit resulting from the transaction agreement with IPH are dependent upon taxable losses utilized by the disposal group through the closing and the resolution of tax matters under audit, including the adoption of recently issued guidance from the IRS related to tangible property repairs and other matters. As a result, tax expense and benefits realized in discontinued operations may differ materially from those recorded as of March 31, 2013.

As the Elgin, Gibson City, and Grand Tower energy center disposal group met the discontinued operations criteria at March 31, 2013, we evaluated whether any impairment existed by comparing the disposal group’s carrying value to the fair value of the disposal group less cost to sell. The fair value was based on the appraised value of these three gas-fired energy centers. In December 2012, Ameren recorded a noncash long-lived asset impairment charge to reduce the carrying value of AER’s energy centers, including the Elgin, Gibson City, and Grand Tower energy centers, to their estimated fair values under the accounting guidance for held and used assets. An immaterial impairment was recorded by Ameren for the three gas-fired energy centers during the three months ended March 31, 2013, as the December 2012 held and used asset impairment charge reduced these energy centers’ disposal group carrying value to their estimated fair value of $133 million. Ameren does not expect to have significant continuing involvement or material cash flows with the Elgin, Gibson City, and Grand Tower energy centers after their divestiture.

Effective with its conclusion that the New AER disposal group and the Elgin, Gibson City and Grand Tower energy centers’ disposal group each met the criteria for discontinued operations presentation, Ameren suspended recording depreciation on these assets in March 2013.

Interest on Genco’s senior notes, which are being assumed by IPH, are included in the “Interest charges” component within the discontinued operations line item in the statement of income (loss). Ameren did not allocate corporate interest to the disposal groups. Additionally, general corporate overhead expenses originally allocated to the disposal groups were classified as expenses of continuing operations.

The following table presents the carrying amounts of the components of assets and liabilities segregated on Ameren's consolidated balance sheets as discontinued operations at March 31, 2013, and December 31, 2012:

	March 31, 2013		December 31, 2012
Current assets of discontinued operations
Cash and cash equivalents	$	25	$	25
Accounts receivable and unbilled revenue	103		102
Materials and supplies	117		134
Mark-to-market derivative assets	101		102
Property and plant, net	607		748
Accumulated deferred income taxes, net	412		373
Other assets	135		116
Total current assets of discontinued operations	$	1,500	$	1,600
Current liabilities of discontinued operations
Accounts payable and other current obligations	$	138	$	133
Mark-to-market derivative liabilities	82		63
Long-term debt, net	824		824
Asset retirement obligations	86		78
Pension and other postretirement benefits	39		40
Other liabilities	29		28
Total current liabilities of discontinued operations	$	1,198	$	1,166
Accumulated other comprehensive gain(a)	$	12	$	19
Noncontrolling interest(b)	$	8	$	8

(a) Accumulated other comprehensive gain related to discontinued operations remains in “Accumulated other comprehensive gain (loss)” on Ameren’s March 31, 2013, and December 31, 2012, balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s balance sheet either before or at the closing of the New AER divestiture.

(b) The 20% ownership interest of EEI not owned by Ameren remains in “Noncontrolling interests” on Ameren’s March 31, 2013, and December 31, 2012, balance sheets. This noncontrolling interest will be removed from Ameren’s balance sheet at the closing of the New AER divestiture.

Ameren will have continuing transactions with New AER after the divestiture is complete. Ameren Illinois has power supply agreements with Marketing Company which are a result of the power procurement process in Illinois administered by the IPA as required by the Illinois Public Utilities Act. Ameren Illinois will continue to purchase power and purchase trade receivables as required by Illinois law, and Ameren will reflect these items as continuing operations after the divestiture occurs. Ameren Illinois and ATXI currently sell, and will continue to sell, transmission services to Marketing Company after the divestiture of New AER is completed. Also, upon the divestiture of New AER, subject to certain exceptions, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture and provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. IPH shall indemnify Ameren for any payments it makes pursuant to these credit support obligations. IPH’s indemnification obligation will be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH’s indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions). Immediately prior to the transaction agreement closing, the cash collateral provided to New AER by Ameren through money pool borrowings will be converted to a note payable to Ameren which will be payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced. Also, within 120 days after closing, a working capital adjustment will be finalized, which may result in a cash payment from Ameren to New AER. Ameren has determined that the continuing cash flows generated by these arrangements are not significant and, accordingly, are not deemed direct cash flows of the divested business. Additionally, these arrangements do not provide Ameren the ability to significantly influence the operating results of New AER after the divestiture is complete. See Note 9 - Related Party Transactions for additional information regarding existing transactions between Ameren and New AER.

For a period of up to 12 months following the closing, Ameren will provide certain transitional services to IPH. Such services will be provided at no charge for 90 days, subject to a $5 million limit; thereafter, services will be provided at cost, except for certain services that may be applied to the $5 million limit to the extent such limit has not been reached by the end of the 90 days period. The transitional services will be provided for six months after the closing and can be extended by IPH on a month-to-month basis for up to an additional six months.

See Note 10 - Commitments and Contingencies for information regarding amendments to the plant transfer agreements between both Genco and Ameren Illinois and AERG and Ameren Illinois as well as other AER related contingencies.

Genco Indenture Provisions

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 March 31, 2013:

	Required Ratio	Actual Ratio
Restricted payment interest coverage ratio(a)	≥1.75	2.3
Additional indebtedness interest coverage ratio(b)	≥2.50	2.3
Additional indebtedness debt-to-capital ratio(b)	≤60%	50	%

(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. 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.

As shown in the table above, 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. During the first quarter of 2013, Genco’s interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and we expect the ratio to remain less than this minimum level through at least 2015. As a result, Genco’s ability to borrow additional funds from external third-party sources is restricted. 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. 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. As stated above, the transaction agreement requires Ameren to operate New AER, including Genco, in the ordinary course prior to the closing.

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Fair Value Measurements (Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt And Preferred Stock) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	$ 7,127	[1],[2]	$ 7,110	[1],[2]
Preferred stock	124	[1],[2]	123	[1],[2]
Fair Value [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	4,645		4,625
Preferred stock	74		73
Fair Value [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	2,027		2,020
Preferred stock	50		49
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	6,158	[1],[2]	6,157	[1],[2]
Preferred stock	142	[1],[2]	142	[1],[2]
Carrying Amount [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	4,006		4,006
Preferred stock	80		80
Carrying Amount [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	1,727		1,727
Preferred stock	$ 62		$ 62

[1] Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

[2] Preferred stock along with the noncontrolling interest of EEI is recorded in “Noncontrolling Interests” on the balance sheet.

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Rate And Regulatory Matters (Narrative-Federal) (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended							12 Months Ended				1 Months Ended
	Nov. 30, 2012 design	Mar. 31, 2013 design	Dec. 31, 2012	Mar. 31, 2013 Ameren Illinois Company [Member]	Dec. 31, 2012 Ameren Illinois Company [Member]	Mar. 31, 2013 Union Electric Company [Member]	Dec. 31, 2012 Union Electric Company [Member]	Mar. 31, 2013 Union Electric Company [Member] New Nuclear Energy Center COL [Member]	Dec. 31, 2012 Union Electric Company [Member] New Nuclear Energy Center COL [Member] Minimum [Member]	Mar. 31, 2013 Union Electric Company [Member] New Nuclear Energy Center COL [Member] Minimum [Member]	Mar. 31, 2013 Union Electric Company [Member] New Nuclear Energy Center COL [Member] Maximum [Member]	Mar. 31, 2013 Wholesale Distribution Rate Case [Member]	Jan. 31, 2011 Wholesale Distribution Rate Case [Member] Ameren Illinois Company [Member] appraiser	Mar. 31, 2013 Wholesale Distribution Rate Case [Member] Ameren Illinois Company [Member]
Rate And Regulatory Matters [Line Items]
Number of Customers, Reached Agreements													4
Number of Wholesale Customers													9
Number of Customers, Remaining on Agreements													5
Current regulatory liabilities		$ 135	$ 100	$ 113	$ 82	$ 23	$ 18					$ 9		$ 9
Department of Energy, Investing Funding Support, Number of Small Modular Reactor Designs		2
Department of Energy, Investing Funding Support, Period		5 years
Department of Energy, Investing Funding Support, Number of Small Modular Reactor Designs Awarded	1
Number of years an COL is valid for									40 years
Investments in Power and Distribution Projects								$ 69		$ 80	$ 100

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Commitments And Contingencies (Tables)

3 Months Ended

Mar. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Schedule of Insurance Coverage at Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at March 31, 2013. 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
Missouri 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) First layer of coverage provides for $500 million in property damage, decontamination, premature decommissioning, and the second layer of coverage provides excess property insurance up to $2.25 billion for losses in excess of the $500 million primary coverage. Effective April 1, 2013, a $1.5 billion sub-limit was established for non-nuclear events.

(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. Effective April 1, 2013, non-nuclear events are sub-limited to $327.6 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 up to $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 9 - Related Party Transactions for more information on this affiliate transaction.

Schedule of Estimated Capital Costs to Comply With Existing and Known Emissions Related Regulations

Continuing Operations:

	2013		2014 - 2017					2018 - 2022					Total
AMO(a)	$	105	$	215	-	$	260	$	795	-	$	975	$	1,115	-	$	1,340

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

Discontinued Operations:

	2013		2014 - 2017					2018 - 2022					Total
Genco(a)	30		100		-	125		220		-	270		350		-	425
AERG	5		20		-	25		20		-	25		45		-	55
Total(b)	$	35	$	120	-	$	150	$	240	-	$	295	$	395	-	$	480

(a) Includes estimated costs of approximately $20 million annually, excluding capitalized interest, from 2013 through 2017 for construction of two Newton energy center scrubbers.

(b) Assumes the Merchant Generation facilities are owned by Ameren.

Schedule of Estimated Obligations for Manufactured Gas Plant Remediation

The following table presents, as of March 31, 2013, the estimated probable obligation to remediate these former MGP sites.

	Estimate				Recorded   Liability(a)
	Low		High
Ameren	$	259	$	342	$	259
Ameren Missouri	5		6		5
Ameren Illinois	254		336		254

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

Schedule of Asbestors-Related Litigation Pending Lawsuits

The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of March 31, 2013:

Ameren	Ameren Missouri	Ameren Illinois	Total(a)
3	66	81	103

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

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2013

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three months ended March 31, 2013, and 2012. 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 4 - Short-term Debt and Liquidity of this report.

			Three Months ended March 31
Agreement	Income Statement Line Item		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2013	$	1	$ (a)
agreements with Ameren Illinois		2012	(b)		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2013	5		(b)
rent and facility services		2012	5		(b)
Ameren Missouri and Genco gas	Operating Revenues	2013	(b)		(a)
transportation agreement		2012	(b)		(a)
Transmission services agreement	Operating Revenues	2013	(a)		6
with Marketing Company		2012	(a)		2
Total Operating Revenues		2013	$	6	$	6
		2012	5		2
Ameren Illinois power supply	Purchased Power	2013	$ (a)		$	26
agreements with Marketing Company		2012	(a)		87
Ameren Illinois power supply	Purchased Power	2013	(a)		1
agreements with Ameren Missouri		2012	(a)		(b)
Total Purchased Power		2013	$ (a)		$	27
		2012	(a)		87
Ameren Services support services	Other Operations and Maintenance	2013	$	31	$	25
agreement		2012	28		23
Insurance premiums(c)	Other Operations and Maintenance	2013	(b)		(a)
		2012	(b)		(a)
Total Other Operations and		2013	$	31	$	25
Maintenance Expenses		2012	28		23
Money pool borrowings (advances)	Interest Charges	2013	$ (b)		$ (b)
		2012	—		(b)

(a) Not applicable.

(b) Amount less than $1 million.

(c) Represents insurance premiums paid to Missouri Energy Risk Assurance Company, an affiliate for replacement power, property damage and terrorism coverage

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Derivative Financial Instruments (Derivatives That Qualify For Regulatory Deferral) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Derivative [Line Items]
Net change in market value of derivatives that qualify for regulatory deferral	$ 56	$ (175)
Union Electric Company [Member]
Derivative [Line Items]
Net change in market value of derivatives that qualify for regulatory deferral	(6)	2
Ameren Illinois Company [Member]
Derivative [Line Items]
Net change in market value of derivatives that qualify for regulatory deferral	62	(160)
Fuel Oils [Member]
Derivative [Line Items]
Net change in market value of derivatives that qualify for regulatory deferral		5
Fuel Oils [Member] | Union Electric Company [Member]
Derivative [Line Items]
Net change in market value of derivatives that qualify for regulatory deferral		5
Natural Gas [Member]
Derivative [Line Items]
Net change in market value of derivatives that qualify for regulatory deferral	36	(18)
Natural Gas [Member] | Union Electric Company [Member]
Derivative [Line Items]
Net change in market value of derivatives that qualify for regulatory deferral	4	(2)
Natural Gas [Member] | Ameren Illinois Company [Member]
Derivative [Line Items]
Net change in market value of derivatives that qualify for regulatory deferral	32	(16)
Power [Member]
Derivative [Line Items]
Net change in market value of derivatives that qualify for regulatory deferral	20	(162)
Power [Member] | Union Electric Company [Member]
Derivative [Line Items]
Net change in market value of derivatives that qualify for regulatory deferral	(10)	(1)
Power [Member] | Ameren Illinois Company [Member]
Derivative [Line Items]
Net change in market value of derivatives that qualify for regulatory deferral	$ 30	$ (144)

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Short-Term Debt And Liquidity (Narrative) (Detail) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Line of Credit Facility [Line Items]
Commercial paper outstanding
Commercial Paper [Member]
Line of Credit Facility [Line Items]
Average daily commercial paper borrowings outstanding	2,000,000	84,000,000
Weighted average interest rate	0.80%	0.94%
Peak short-term borrowings	21,000,000	186,000,000
Peak short-term borrowings interest rate	0.85%	1.25%
Utilities [Member]
Line of Credit Facility [Line Items]
Weighted average interest rate	0.11%	0.11%
Non State Regulated Subsidiaries [Member]
Line of Credit Facility [Line Items]
Weighted average interest rate	0.22%	0.76%
Credit Agreements 2012 [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 2,060,000,000
Actual debt-to-capital ratio percentage	0.52
Minimum ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date	2.0 to 1
Covenant terms, ratio of consolidated operational funds to consolidated interest expense, minimum
Current ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date	5.1 to 1.0
Covenant compliance, ratio of consolidated operational funds to consolidated interest expense
Credit Agreements 2012 [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Actual debt-to-capital ratio percentage	0.65
Credit Agreements 2012 [Member] | Union Electric Company [Member]
Line of Credit Facility [Line Items]
Actual debt-to-capital ratio percentage	0.48
Credit Agreements 2012 [Member] | Ameren Illinois Company [Member]
Line of Credit Facility [Line Items]
Actual debt-to-capital ratio percentage	0.42

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Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Components Of Net Periodic Benefit Cost

The following table presents the components of the net periodic benefit cost for Ameren’s pension and postretirement benefit plans for the three months ended March 31, 2013, and 2012:

	Pension Benefits						Postretirement Benefits
	Three Months						Three Months
	2013			2012			2013			2012
Service cost	$	24		$	21		$	6		$	6
Interest cost	40			42			12			13
Expected return on plan assets	(54		)	(52		)	(16		)	(14		)
Amortization of:
Prior service cost (benefit)	(1		)	(1		)	(1		)	(1		)
Actuarial loss	22			19			2			3
Net periodic benefit cost	$	31		$	29		$	3		$	7

Summary Of Benefit Plan Costs Incurred

Ameren Missouri and Ameren Illinois are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three months ended March 31, 2013, and 2012:

	Pension Costs				Postretirement Costs
	Three Months				Three Months
	2013		2012		2013		2012
Ameren Missouri	$	18	$	16	$	2	$	5
Ameren Illinois	10		10		1		2
Other	3		3		—		—
Ameren(a)	$	31	$	29	$	3	$	7

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

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2013

Segment Reporting [Abstract]

Schedule Of Segment Reporting Information By Segment

The following table presents information about the revenues and specified items included in Ameren’s net income for the three months ended March 31, 2013, and 2012, and total assets as of March 31, 2013, and December 31, 2012.

Three Months	Ameren Missouri		Ameren Illinois		Other			Intersegment Eliminations			Consolidated
2013
External revenues	$	789	$	684	$	2		$	—		$	1,475
Intersegment revenues	7		—		2			(9		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	40		31		(17		)	—			54
2012
External revenues	$	686	$	724	$	2		$	—		$	1,412
Intersegment revenues	5		—		1			(6		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	21		27		(11		)	—			37
As of March 31, 2013:
Total assets	$	12,867	$	7,288	$	1,289		$	(992	)	$	20,452	(a)
As of December 31, 2012:
Total assets	$	13,043	$	7,282	$	1,228		$	(944	)	$	20,609	(a)

(a)    Excludes “Current assets of discontinued operations.” See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

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Summary Of Significant Accounting Policies

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 its equity interests in 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, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes.

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

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Immediately prior to Ameren’s entry into the transaction agreement with IPH, on March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. Ameren has commenced a sale process for these three gas-fired energy centers and expects a third-party sale to be completed during 2013. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding these divestitures. As a result of the transaction agreement with IPH and Ameren’s plan to sell its Elgin, Gibson City, and Grand Tower gas-fired energy centers, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation. Therefore, Ameren has segregated New AER’s and the Elgin, Gibson City, and Grand Tower gas-fired energy centers’ operating results, assets, and liabilities and presented them separately as discontinued operations for all periods presented in this report. Unless otherwise noted, these notes to Ameren’s financial statements have been revised to exclude discontinued operations for all periods presented. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding that presentation.

The financial statements of Ameren 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.

During preparation of the 2012 annual statements of cash flows, it was identified that Ameren’s and Ameren Missouri’s 2012 interim statements of cash flows incorrectly classified certain activity from the nuclear decommissioning trust fund. Although not material, operating cash flows were overstated by $14 million, $26 million, and $49 million through the year-to-date first, second, and third quarters of 2012, respectively. The overstated operating cash flows resulted in the investing cash flows being understated by the same amounts. The 2012 first quarter cash flows for Ameren and Ameren Missouri have been revised in this report to correct for this error. The 2012 statements of cash flows for the second and third quarters of 2012 will be revised to correct for this error in the Ameren and Ameren Missouri 2013 second and third quarter reports.

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three months ended March 31, 2013, and 2012. The number of dilutive restricted stock shares and performance share units had an immaterial impact on earnings per share.

Stock-based Compensation

A summary of nonvested shares as of March 31, 2013, and changes during the three months ended March 31, 2013, under the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

	Performance Share Units
	Share Units		Weighted-average Fair Value Per Unit at Grant Date
Nonvested at January 1, 2013	1,192,487		$	33.56
Granted(a)	832,034		31.19
Forfeitures	(5,456	)	32.67
Vested(b)	(122,671	)	31.19
Nonvested at March 31, 2013	1,896,394		$	32.68

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2013 under the 2006 Plan.

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

The fair value of each share unit awarded in January 2013 under the 2006 Plan was determined to be $31.19. That amount was based on Ameren’s closing common share price of $30.72 at December 31, 2012, 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, 2013. 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 0.36%, volatility of 12% to 21% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.

Intangible Assets

Ameren and Ameren Missouri classify emission allowances and renewable energy credits as intangible assets. Ameren Illinois consumes renewable energy credits as they are purchased through the IPA procurement process and expenses them immediately. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

At March 31, 2013, 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 Ameren’s and Ameren Missouri’s renewable energy credits was $16 million and $16 million, respectively, at March 31, 2013. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $14 million and $14 million, respectively, at December 31, 2012.

Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. In accordance with MoPSC's 2012 electric rate order, almost all of Ameren Missouri's amortization of intangible assets is deferred as a regulatory asset pending future recovery from customers through rates. 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, and Ameren Illinois, during the three months ended March 31, 2013, and 2012.

		Three Months
		2013		2012
Ameren Missouri	$	(a)	$	(a)
Ameren Illinois		4		(a)
Ameren	$	4	$	(a)

(a) Less than $1 million.

Excise Taxes

Excise taxes levied on us are reflected on Ameren Missouri electric customer bills and on 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 months ended March 31, 2013, and 2012:

	Three Months
	2013		2012
Ameren Missouri	$	33	$	27
Ameren Illinois	22		18
Ameren	$	55	$	45

Uncertain Tax Positions

The amount of unrecognized tax benefits as of March 31, 2013, was $190 million, $126 million, and $4 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The amount of unrecognized tax benefits (detriments) as of March 31, 2013, that would impact the effective tax rate, if recognized, was $48 million, $1 million, and $(1) million for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The Ameren amount increased by $47 million in the first three months of 2013. This increase was primarily due to uncertainty related to the historical computation of Ameren’s tax basis in its stock investment in AER.

Ameren’s federal income tax returns for the years 2007 through 2010 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2011 is currently under examination.

It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the next 12 months for the years 2007 through 2010. This settlement, primarily related to uncertain tax positions for capitalization versus currently deductible repair expense and research tax deductions, is expected to result in a decrease in uncertain tax benefits of approximately $126 million, $110 million, and $5 million for Ameren, Ameren Missouri and Ameren Illinois, respectively. In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe any such increases or decreases, including the decrease from the reasonably possible IRS Appeals Office settlement discussed above, would be material to their results of operations, financial position, or liquidity.

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.

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri, and Ameren Illinois increased compared to December 31, 2012, to reflect the accretion of obligations to their fair values.

Based on the transaction agreement to divest New AER to IPH, Ameren will retain the AROs associated with the Meredosia and Hutsonville energy centers. Therefore, these AROs are classified as continuing operations. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

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. A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren for the three months ended March 31, 2013, and 2012, is shown below:

	Three Months
	2013			2012
Ameren:
Noncontrolling interests, beginning of period (a)	$	151		$	149
Net income from continuing operations attributable to noncontrolling interests	2			2
Net income (loss) from discontinued operations attributable to noncontrolling interests	—			(2		)
Dividends paid to noncontrolling interest holders	(2		)	(2		)
Noncontrolling interests, end of period (a)	$	151		$	147

(a) Includes the 20% EEI ownership interest not owned by Ameren. The assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Current assets of discontinued operations” and “Current liabilities of discontinued operations,” however, the 20% ownership interest not owned by Ameren was included in “Noncontrolling interests” on Ameren’s March 31, 2013, and December 31, 2012 balance sheet. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

Accounting and Reporting Developments

The following is a summary of recently adopted authoritative accounting guidance that could impact the Ameren Companies.

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect the Ameren Companies’ results of operations, financial position, or liquidity.

In February 2013, FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. This guidance was effective for the Ameren Companies beginning in the first quarter of 2013. The implementation of this amendment did not affect the Ameren Companies’ results of operations, financial position, or liquidity. The only amounts reclassified out of accumulated OCI for the Ameren Companies related to pension and other postretirement plan activity. These amounts were immaterial during the first quarter of 2013 and 2012, and therefore no additional disclosures required.

Disclosures about Offsetting Assets and Liabilities

In December 2011, FASB issued additional authoritative guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The amendments did not affect the Ameren Companies’ results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. The Ameren Companies adopted this guidance for the first quarter of 2013. See Note 7 - Derivative Financial Instruments for the required additional disclosures.

XML

Summary Of Significant Accounting Policies (Narrative) (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended					3 Months Ended					3 Months Ended			1 Months Ended	3 Months Ended		0 Months Ended
	Mar. 31, 2013	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2012	Mar. 31, 2013 Union Electric Company [Member]	Sep. 30, 2012 Union Electric Company [Member]	Jun. 30, 2012 Union Electric Company [Member]	Mar. 31, 2012 Union Electric Company [Member]	Dec. 31, 2012 Union Electric Company [Member]	Mar. 31, 2013 Ameren Illinois Company [Member]	Mar. 31, 2013 Electric Energy, Inc [Member]	Dec. 31, 2012 Electric Energy, Inc [Member]	Jan. 31, 2013 Performance Shares [Member]	Mar. 31, 2013 Performance Shares [Member]		Mar. 14, 2013 Elgin, Gibson City and Grand Tower Energy Centers [Member] Ameren Energy Generating Company [Member]
Basis Of Presentation And Significant Accounting Policies [Line Items]
Ownership interest												80.00%
Initial payment received																	$ 100
Identified immaterial errors		49	26	14			49	26	14
Fair value of each share unit, per share														$ 31.19	$ 31.19	[1]
Closing common share price					$ 30.72
Performance period															3 years
Three-year risk-free rate															0.36%
Volatility rate, minimum															12.00%
Volatility rate, maximum															21.00%
Book value	16				14	16				14
Unrecognized tax benefits	190					126					4
Unrecognized tax benefits (detriments) that would impact effective tax rate	48					1					(1)
Increase in Unrecognized Tax benefits	47
Estimated unrecognized tax decreases resulting from settlements with taxing authorities	$ 126					$ 110					$ 5
Percentage of EEI not owned by Ameren												20.00%	20.00%

[1] Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2013 under the 2006 Plan

XML

Divestiture Transactions and Discontinued Operations (Debt Ratios) (Details) (Ameren Energy Generating Company [Member])	3 Months Ended
	Mar. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Restricted payment interest coverage ratio, Actual	2.3	[1],[2]
Additional indebtedness debt-to-capital ratio, Actual	0.50	[1]
Minimum [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Additional indebtedness debt-to-capital ratio, Actual	0.60	[1]
Restricted payment interest coverage ratio, Required	1.75	[2]
Additional indebtedness interest coverage ratio, Required	2.5	[1]

[1] 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. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

[2] 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.

XML

Derivative Financial Instruments (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012 Union Electric Company [Member]
Derivative [Line Items]
Counterparty letters of credit held as collateral	$ 1	$ 1

XML

Retirement Benefits (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined benefit plan, estimated future employer contributions in each of the next five years	$ 550
Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined benefit plan, estimated future employer contributions in each of the next five years	60
Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined benefit plan, estimated future employer contributions in each of the next five years	$ 150

XML

Consolidated Statement of Income (Loss) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Operating Revenues:
Electric	$ 1,088		$ 1,064
Gas	387		348
Operating Revenues	1,475		1,412
Operating Expenses:
Fuel	213		181
Purchased power	151		209
Gas purchased for resale	230		215
Other operations and maintenance	399		369
Depreciation and amortization	175		167
Taxes other than income taxes	122		113
Total operating expenses	1,290		1,254
Operating Income	185		158
Other Income and Expenses:
Miscellaneous income	15	[1]	17	[1]
Miscellaneous expense	8	[1]	15	[1]
Total other income (expense)	7		2
Interest Charges	101		98
Income (Loss) Before Income Taxes	91		62
Income Taxes	35		23
Income from Continuing Operations	56		39
Loss from Discontinued Operations, Net of Taxes (Note 2)	(199)		(442)
Net Loss	(143)		(403)
Comprehensive Income (Loss)	(152)		(388)
Less: Net Income (Loss) Attributable to Noncontrolling Interests:
Continuing Operations	2		2
Discontinued Operations			(2)
Net Income (Loss):
Continuing Operations	54		37
Discontinued Operations	(199)		(440)
Net Income (Loss)	(145)		(403)
Earnings (Loss) per Common Share – Basic and Diluted:
Continuing Operations (in dollars per share)	$ 0.22		$ 0.15
Discontinued Operations (in dollars per share)	$ (0.82)		$ (1.81)
Earnings per Common Share - Basic and Diluted	$ (0.60)		$ (1.66)
Dividends per Common Share	$ 0.40		$ 0.40
Average Common Shares Outstanding	242.6		242.6
Union Electric Company [Member]
Operating Revenues:
Electric	732		636
Gas	64		55
Operating Revenues	796		691
Operating Expenses:
Fuel	213		180
Purchased power	26		20
Gas purchased for resale	37		32
Other operations and maintenance	221		202
Depreciation and amortization	111		108
Taxes other than income taxes	77		71
Total operating expenses	685		613
Operating Income	111		78
Other Income and Expenses:
Miscellaneous income	14		15
Miscellaneous expense	5		3
Total other income (expense)	9		12
Interest Charges	60		56
Income (Loss) Before Income Taxes	60		34
Income Taxes	19		12
Net Loss	41		22
Other Comprehensive Income	0		0
Comprehensive Income (Loss)	41		22
Net Income (Loss):
Net Income (Loss)	41		22
Earnings (Loss) per Common Share – Basic and Diluted:
Preferred Stock Dividends	1		1
Net Income Available to Common Stockholder	40		21
Ameren Illinois Company [Member]
Operating Revenues:
Electric	360		431
Gas	324		293
Operating Revenues	684		724
Operating Expenses:
Purchased power	127		190
Gas purchased for resale	193		183
Other operations and maintenance	176		168
Depreciation and amortization	61		55
Taxes other than income taxes	42		39
Total operating expenses	599		635
Operating Income	85		89
Other Income and Expenses:
Miscellaneous income	1		1
Miscellaneous expense	3		11
Total other income (expense)	(2)		(10)
Interest Charges	31		33
Income (Loss) Before Income Taxes	52		46
Income Taxes	20		18
Net Loss	32		28
Pension and other postretirement benefit plan activity, net of income taxes	(1)		(1)
Comprehensive Income (Loss)	31		27
Net Income (Loss):
Net Income (Loss)	32		28
Earnings (Loss) per Common Share – Basic and Diluted:
Preferred Stock Dividends	1		1
Net Income Available to Common Stockholder	$ 31		$ 27

[1] Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

XML

Long-Term Debt And Equity Financings (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Long-Term Debt And Equity Financings [Line Items]
Excess in indebtedness upon default of maturity	$ 25
Ameren Missouri And Ameren Illinois [Member]
Long-Term Debt And Equity Financings [Line Items]
Assumed interest rate	6.00%
Dividend rate	7.00%
Ameren Illinois Company [Member] | Federal Energy Regulatory Commission Restriction [Member] | Actual Ratio [Member]
Long-Term Debt And Equity Financings [Line Items]
Common stock equity to total capitalization	57.00%
Ameren Illinois Company [Member] | Minimum [Member] | Federal Energy Regulatory Commission Restriction [Member]
Long-Term Debt And Equity Financings [Line Items]
Common stock equity to total capitalization	30.00%

XML

Consolidated Balance Sheet (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Accounts receivable - trade allowance for doubtful accounts	$ 22	$ 17
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	400.0	400.0
Common stock, shares outstanding	242.6	242.6
Union Electric Company [Member]
Accounts receivable - trade allowance for doubtful accounts	8	5
Common stock, par value	$ 5	$ 5
Common stock, shares authorized	150.0	150.0
Common stock, shares outstanding	102.1	102.1
Ameren Illinois Company [Member]
Accounts receivable - trade allowance for doubtful accounts	$ 14	$ 12
Common stock, no par value
Common stock, shares authorized	45.0	45.0
Common stock, shares outstanding	25.5	25.5

XML

Fair Value Measurements (Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	$ 434	[1]	$ 406	[2]
Assets fair value	471		435
Excluded receivables, payables, and accrued income, net	3		2
Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	434	[1]	406	[2]
Assets fair value	462		434
Fuel Oils [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	7	[3]	8	[3]
Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	3	[3]
Commodity Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	37	[3]	29	[3]
Derivative liabilities	183	[3]	230	[3]
Commodity Contracts [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	28	[3]	28	[3]
Derivative liabilities	32	[3]	25	[3]
Commodity Contracts [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	9		1
Derivative liabilities	151	[3]	205	[3]
Commodity Contracts [Member] | Fuel Oils [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	10	[3]	12	[3]
Derivative liabilities	3	[3]	4	[3]
Commodity Contracts [Member] | Fuel Oils [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	10	[3]	12	[3]
Derivative liabilities	3	[3]	4	[3]
Commodity Contracts [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	8	[3]	2	[3]
Derivative liabilities	79	[3]	109	[3]
Commodity Contracts [Member] | Natural Gas [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	2	[3]	1	[3]
Derivative liabilities	12	[3]	15	[3]
Commodity Contracts [Member] | Natural Gas [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	6	[3]	1	[3]
Derivative liabilities	67	[3]	94	[3]
Commodity Contracts [Member] | Power [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	19	[3]	15	[3]
Derivative liabilities	99	[3]	115	[3]
Commodity Contracts [Member] | Power [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	16	[3]	15	[3]
Derivative liabilities	15	[3]	4	[3]
Commodity Contracts [Member] | Power [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	3	[3]		[3]
Derivative liabilities	84	[3]	111	[3]
Commodity Contracts [Member] | Uranium [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	2	[3]	2	[3]
Commodity Contracts [Member] | Uranium [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	2	[3]	2	[3]
Cash and cash equivalents [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	2	[1]	1	[2]
Cash and cash equivalents [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	2	[1]	1	[2]
Equity Securities [Member] | U.S. large capitalization [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	294	[1]	264	[2]
Equity Securities [Member] | U.S. large capitalization [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	294	[1]	264	[2]
Debt Securities [Member] | Corporate bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	48	[1]	47	[2]
Debt Securities [Member] | Corporate bonds [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	48	[1]	47	[2]
Debt Securities [Member] | Municipal bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	1	[2]
Debt Securities [Member] | Municipal bonds [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	1	[2]
Debt Securities [Member] | US treasury and government securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	77	[1]	81	[2]
Debt Securities [Member] | US treasury and government securities [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	77	[1]	81	[2]
Debt Securities [Member] | Asset-backed Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	11	[1]	11	[2]
Debt Securities [Member] | Asset-backed Securities [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	11	[1]	11	[2]
Debt Securities [Member] | Other Debt Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	1	[2]
Debt Securities [Member] | Other Debt Securities [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	1	[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	296	[1]	265	[2]
Assets fair value	300		269
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	296	[1]	265	[2]
Assets fair value	299		269
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Commodity Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	4	[3]	4	[3]
Derivative liabilities	6	[3]	8	[3]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Commodity Contracts [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	3	[3]	4	[3]
Derivative liabilities	6	[3]	8	[3]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Commodity Contracts [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Commodity Contracts [Member] | Fuel Oils [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	3	[3]	4	[3]
Derivative liabilities	1	[3]	1	[3]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Commodity Contracts [Member] | Fuel Oils [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	3	[3]	4	[3]
Derivative liabilities	1	[3]	1	[3]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Commodity Contracts [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[3]		[3]
Derivative liabilities	5	[3]	7	[3]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Commodity Contracts [Member] | Natural Gas [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		[3]		[3]
Derivative liabilities	5	[3]	7	[3]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Commodity Contracts [Member] | Natural Gas [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[3]
Derivative liabilities				[3]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Cash and cash equivalents [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	2	[1]	1	[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Cash and cash equivalents [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	2	[1]	1	[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Equity Securities [Member] | U.S. large capitalization [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	294	[1]	264	[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] | Equity Securities [Member] | U.S. large capitalization [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	294	[1]	264	[2]
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	138	[1]	141	[2]
Assets fair value	149		144
Significant Other Observable Inputs (Level 2) [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	138	[1]	141	[2]
Assets fair value	146		143
Significant Other Observable Inputs (Level 2) [Member] | Commodity Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	11	[3]	3	[3]
Derivative liabilities	81	[3]	103	[3]
Significant Other Observable Inputs (Level 2) [Member] | Commodity Contracts [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	8	[3]	2	[3]
Derivative liabilities	14	[3]	9	[3]
Significant Other Observable Inputs (Level 2) [Member] | Commodity Contracts [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	3		1
Derivative liabilities	67	[3]	94	[3]
Significant Other Observable Inputs (Level 2) [Member] | Commodity Contracts [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	4	[3]	2	[3]
Derivative liabilities	73	[3]	102	[3]
Significant Other Observable Inputs (Level 2) [Member] | Commodity Contracts [Member] | Natural Gas [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[3]	1	[3]
Derivative liabilities	6	[3]	8	[3]
Significant Other Observable Inputs (Level 2) [Member] | Commodity Contracts [Member] | Natural Gas [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	3	[3]	1	[3]
Derivative liabilities	67	[3]	94	[3]
Significant Other Observable Inputs (Level 2) [Member] | Commodity Contracts [Member] | Power [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	7	[3]	1	[3]
Derivative liabilities	8	[3]	1	[3]
Significant Other Observable Inputs (Level 2) [Member] | Commodity Contracts [Member] | Power [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	7	[3]	1	[3]
Derivative liabilities	8	[3]	1	[3]
Significant Other Observable Inputs (Level 2) [Member] | Commodity Contracts [Member] | Power [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets				[3]
Derivative liabilities				[3]
Significant Other Observable Inputs (Level 2) [Member] | Debt Securities [Member] | Corporate bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	48	[1]	47	[2]
Significant Other Observable Inputs (Level 2) [Member] | Debt Securities [Member] | Corporate bonds [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	48	[1]	47	[2]
Significant Other Observable Inputs (Level 2) [Member] | Debt Securities [Member] | Municipal bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	1	[2]
Significant Other Observable Inputs (Level 2) [Member] | Debt Securities [Member] | Municipal bonds [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	1	[2]
Significant Other Observable Inputs (Level 2) [Member] | Debt Securities [Member] | US treasury and government securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	77	[1]	81	[2]
Significant Other Observable Inputs (Level 2) [Member] | Debt Securities [Member] | US treasury and government securities [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	77	[1]	81	[2]
Significant Other Observable Inputs (Level 2) [Member] | Debt Securities [Member] | Asset-backed Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	11	[1]	11	[2]
Significant Other Observable Inputs (Level 2) [Member] | Debt Securities [Member] | Asset-backed Securities [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	11	[1]	11	[2]
Significant Other Observable Inputs (Level 2) [Member] | Debt Securities [Member] | Other Debt Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	1	[2]
Significant Other Observable Inputs (Level 2) [Member] | Debt Securities [Member] | Other Debt Securities [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	1	[2]
Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets fair value	22		22	[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets fair value	17		22
Significant Other Unobservable Inputs (Level 3) [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	22	[3]	22	[3]
Derivative liabilities	96	[3]	119	[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	17	[3]	22	[3]
Derivative liabilities	12	[3]	8	[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	5
Derivative liabilities	84	[3]	111	[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member] | Fuel Oils [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	7	[3]	8	[3]
Derivative liabilities	2	[3]	3	[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member] | Fuel Oils [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	7	[3]	8	[3]
Derivative liabilities	2	[3]	3	[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	3	[3]		[3]
Derivative liabilities	1	[3]		[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member] | Natural Gas [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[3]
Derivative liabilities	1	[3]		[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member] | Natural Gas [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	2	[3]		[3]
Derivative liabilities				[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member] | Power [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	12	[3]	14	[3]
Derivative liabilities	91	[3]	114	[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member] | Power [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	9	[3]	14	[3]
Derivative liabilities	7	[3]	3	[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member] | Power [Member] | Ameren Illinois Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	3	[3]		[3]
Derivative liabilities	84	[3]	111	[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member] | Uranium [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	2	[3]	2	[3]
Significant Other Unobservable Inputs (Level 3) [Member] | Commodity Contracts [Member] | Uranium [Member] | Union Electric Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	$ 2	[3]	$ 2	[3]

[1] Balance excludes $3 million of receivables, payables, and accrued income, net.

[2] Balance excludes $2 million of receivables, payables, and accrued income, net.

[3] The derivative asset and liability balances are presented net of counterparty credit considerations.

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Summary Of Significant Accounting Policies (Schedule Of Excise Taxes) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Accounting Policies [Line Items]
Excise tax expense	$ 55	$ 45
Union Electric Company [Member]
Accounting Policies [Line Items]
Excise tax expense	33	27
Ameren Illinois Company [Member]
Accounting Policies [Line Items]
Excise tax expense	$ 22	$ 18

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Commitments And Contingencies (Callaway Energy Center) (Detail) (USD $)	3 Months Ended
	Mar. 31, 2013 Week
Commitments And Contingencies [Line Items]
Maximum Coverages	$ 12,594,000,000	[1]
Maximum Assessments for Single Incidents	118,000,000
Threshold for which a retrospective assessment for a covered loss is necessary	375,000,000
Annual payment in the event of an incident at any licensed commercial reactor	17,500,000
Aggregate maximum assessment per incident under Price-Anderson liability provisions of Atomic Energy Act	118,000,000
Maximum annual payment in calendar year per reactor incident under Price Andersen Liability Provisions of Atomic Energy Act	17,500,000
Amount of primary property liability coverage	500,000,000
Amount of coverage in excess of primary property liability coverage	2,250,000,000
Losses in excess of primary coverage	500,000,000
Sub-limit for non-nuclear events	1,500,000,000
Amount of weekly indemnity coverage commencing eight weeks after power outage	4,500,000
Number of weeks of coverage after the first eight weeks of an outage	52
Amount of additional weekly indemnity coverage commencing after initial indemnity coverage	3,600,000
Number of additional weeks after initial indemnity coverage for power outage, minimum	71
Amount of secondary weekly indemnity coverage for prolonged nuclear plant outage in excess of primary indemnity coverage	900,000
Inflationary adjustment prescribed by most recent Price-Anderson Act renewal, in years	5 years
Aggregate nuclear power industry insurance policy limit for losses from terrorist attacks within twelve month period	3,240,000,000
Replacement Power - Nuclear Electric Insurance Ltd [Member]
Commitments And Contingencies [Line Items]
Maximum Coverages	490,000,000	[2]
Maximum Assessments for Single Incidents	9,000,000
Amount of weekly indemnity coverage thereafter not exceeding policy limit	490,000,000
Sub-limit of for non-nuclear events	327,600,000
Replacement Power - Energy Risk Assurance Company [Member]
Commitments And Contingencies [Line Items]
Maximum Coverages	64,000,000	[3]
Amount of weekly indemnity coverage thereafter not exceeding policy limit	3,600,000
Public Liability And Nuclear Worker Liability - American Nuclear Insurers [Member]
Commitments And Contingencies [Line Items]
Maximum Coverages	375,000,000
Public Liability And Nuclear Worker Liability - Pool Participation [Member]
Commitments And Contingencies [Line Items]
Maximum Coverages	12,219,000,000	[4]
Maximum Assessments for Single Incidents	118,000,000	[5]
Property Damage - Nuclear Electric Insurance Ltd [Member]
Commitments And Contingencies [Line Items]
Maximum Coverages	2,750,000,000	[6]
Maximum Assessments for Single Incidents	$ 23,000,000

[1] 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.

[2] 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. Effective April 1, 2013, non-nuclear events are sub-limited to $327.6 million

[3] 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 up to $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 9 - Related Party Transactions for more information on this affiliate transaction.

[4] Provided through mandatory participation in an industry-wide retrospective premium assessment program.

[5] 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.

[6] First layer of coverage provides for $500 million in property damage, decontamination, premature decommissioning, and the second layer of coverage provides excess property insurance up to $2.25 billion for losses in excess of the $500 million primary coverage. Effective April 1, 2013, a $1.5 billion sub-limit was established for non-nuclear events.

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Summary Of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Summary Of Nonvested Shares Related To Long-Term Incentive Plan

A summary of nonvested shares as of March 31, 2013, and changes during the three months ended March 31, 2013, under the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

	Performance Share Units
	Share Units		Weighted-average Fair Value Per Unit at Grant Date
Nonvested at January 1, 2013	1,192,487		$	33.56
Granted(a)	832,034		31.19
Forfeitures	(5,456	)	32.67
Vested(b)	(122,671	)	31.19
Nonvested at March 31, 2013	1,896,394		$	32.68

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2013 under the 2006 Plan.

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

Schedule Of Amortization Expense Based On Usage Of Renewable Energy Credits And Emission Allowances

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, and Ameren Illinois, during the three months ended March 31, 2013, and 2012.

		Three Months
		2013		2012
Ameren Missouri	$	(a)	$	(a)
Ameren Illinois		4		(a)
Ameren	$	4	$	(a)

(a) Less than $1 million.

Schedule of Excise Taxes

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 months ended March 31, 2013, and 2012:

	Three Months
	2013		2012
Ameren Missouri	$	33	$	27
Ameren Illinois	22		18
Ameren	$	55	$	45

Equity Changes Attributable To Noncontrolling Interest

A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren for the three months ended March 31, 2013, and 2012, is shown below:

	Three Months
	2013			2012
Ameren:
Noncontrolling interests, beginning of period (a)	$	151		$	149
Net income from continuing operations attributable to noncontrolling interests	2			2
Net income (loss) from discontinued operations attributable to noncontrolling interests	—			(2		)
Dividends paid to noncontrolling interest holders	(2		)	(2		)
Noncontrolling interests, end of period (a)	$	151		$	147

(a) Includes the 20% EEI ownership interest not owned by Ameren. The assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Current assets of discontinued operations” and “Current liabilities of discontinued operations,” however, the 20% ownership interest not owned by Ameren was included in “Noncontrolling interests” on Ameren’s March 31, 2013, and December 31, 2012 balance sheet. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

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Summary Of Significant Accounting Policies (Equity Changes Attributable To Noncontrolling Interest) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012		Mar. 31, 2013 Electric Energy, Inc [Member]	Dec. 31, 2012 Electric Energy, Inc [Member]
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Noncontrolling interest, beginning of period	$ 151	[1]	$ 149	[1]
Net income from continuing operations attributable to noncontrolling interests	2		2
Net income (loss) from discontinued operations attributable to noncontrolling interests			(2)
Dividends paid to noncontrolling interest holders	(2)		(2)
Noncontrolling interest, end of period	$ 151	[1]	$ 147	[1]
Percentage of EEI not owned by Ameren					20.00%	20.00%

[1] Includes the 20% EEI ownership interest not owned by Ameren. The assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Current assets of discontinued operations” and “Current liabilities of discontinued operations,” however, the 20% ownership interest not owned by Ameren was included in “Noncontrolling interests” on Ameren’s March 31, 2013, and December 31, 2012 balance sheet. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

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Long-Term Debt And Equity Financings (Tables)

3 Months Ended

Mar. 31, 2013

Long-Term Debt And Equity Financings [Abstract]

Schedule Of Coverage Ratios

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. 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 as of March 31, 2013, 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	4.7	$	4,304		≥2.5	128.1	$	2,454
Ameren Illinois	≥2.0	7.2		3,499	(d)	≥1.5	2.7		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 requir

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Commitments And Contingencies (Pumped-Storage Hydroelectric Facility Breach) (Detail) (Union Electric Company [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2013
Union Electric Company [Member]
Loss Contingencies [Line Items]
Insurance settlements receivable	$ 68

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Consolidated Statement Of Cash Flows (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Cash Flows From Operating Activities:
Net income (loss)	$ (143)		$ (403)
Loss from discontinued operations, net of taxes	199		442
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	166		156
Amortization of nuclear fuel	20		21
Amortization of debt issuance costs and premium/discounts	6		4
Deferred income taxes and investment tax credits, net	40		30
Allowance for equity funds used during construction	(8)	[1]	(9)	[1]
Stock-based compensation costs	9		8
Other	(3)		(5)
Changes in assets and liabilities:
Receivables	(95)		93
Materials and supplies	127		79
Accounts and wages payable	(127)		(208)
Taxes accrued	41		22
Assets, other	52		19
Liabilities, other	29		23
Pension and other postretirement benefits	3		41
Counterparty collateral, net	26		(9)
Net cash provided by operating activities - continuing operations	342		304
Net cash provided by operating activities - discontinued operations	37		79
Net cash provided by operating activities	379		383
Cash Flows From Investing Activities:
Capital expenditures	(275)		(245)
Nuclear fuel expenditures	(11)		(38)
Purchases of securities - nuclear decommissioning trust fund	(35)		(109)
Sales and maturities of securities - nuclear decommissioning trust fund	32		102
Other	(2)		(2)
Net cash used in investing activities - continuing operations	(291)		(292)
Net cash used in investing activities - discontinued operations	(12)		(19)
Net cash used in investing activities	(303)		(311)
Cash Flows From Financing Activities:
Dividends on common stock	(97)		(90)
Dividends paid to noncontrolling interest holders	(2)		(2)
Short-term debt, net	0		(22)
Advances received for construction	0		1
Net cash used in financing activities - continuing operations	(99)		(113)
Net cash used in financing activities - discontinued operations	0		0
Net cash used in financing activities	(99)		(113)
Net change in cash and cash equivalents	(23)		(41)
Cash and cash equivalents at beginning of year	184		248
Cash and cash equivalents at end of period	161		207
Noncash financing activity - dividends on common stock			(7)
Union Electric Company [Member]
Cash Flows From Operating Activities:
Net income (loss)	41		22
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	104		100
Amortization of nuclear fuel	20		21
Amortization of debt issuance costs and premium/discounts	2		2
Deferred income taxes and investment tax credits, net	(8)		2
Allowance for equity funds used during construction	(7)		(8)
Changes in assets and liabilities:
Receivables	(50)		61
Materials and supplies	22		(26)
Accounts and wages payable	(139)		(136)
Taxes accrued	38		39
Assets, other	38		13
Liabilities, other	5		0
Pension and other postretirement benefits	2		17
Net cash provided by operating activities	68		107
Cash Flows From Investing Activities:
Capital expenditures	(137)		(157)
Nuclear fuel expenditures	(11)		(38)
Purchases of securities - nuclear decommissioning trust fund	(35)		(109)
Sales and maturities of securities - nuclear decommissioning trust fund	32		102
Money pool advances, net	24		0
Other	(2)		(2)
Net cash used in investing activities	(129)		(204)
Cash Flows From Financing Activities:
Dividends on common stock	(90)		(100)
Dividends on preferred stock	(1)		(1)
Money pool borrowings, net	5		0
Net cash used in financing activities	(86)		(101)
Net change in cash and cash equivalents	(147)		(198)
Cash and cash equivalents at beginning of year	148		201
Cash and cash equivalents at end of period	1		3
Ameren Illinois Company [Member]
Cash Flows From Operating Activities:
Net income (loss)	32		28
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	60		52
Amortization of debt issuance costs and premium/discounts	3		2
Deferred income taxes and investment tax credits, net	50		55
Other	(1)		(2)
Changes in assets and liabilities:
Receivables	(58)		35
Materials and supplies	105		103
Accounts and wages payable	9		(16)
Taxes accrued	3		0
Assets, other	16		2
Liabilities, other	24		26
Pension and other postretirement benefits	1		15
Counterparty collateral, net	27		(11)
Net cash provided by operating activities	271		289
Cash Flows From Investing Activities:
Capital expenditures	(133)		(86)
Money pool advances, net	(5)		0
Net cash used in investing activities	(138)		(86)
Cash Flows From Financing Activities:
Dividends on common stock	(15)		(37)
Dividends on preferred stock	(1)		(1)
Money pool borrowings, net	(24)		0
Advances received for construction	0		1
Net cash used in financing activities	(40)		(37)
Net change in cash and cash equivalents	93		166
Cash and cash equivalents at beginning of year	0		21
Cash and cash equivalents at end of period	$ 93		$ 187

[1] Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

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Consolidated Statement of Income (Loss) (Parenthetical) (Ameren Illinois Company [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Ameren Illinois Company [Member]
Pension and other postretirement benefit plan activity, tax expense (benefit)	$ (1)	$ 0

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Commitments And Contingencies

3 Months Ended

Mar. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

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 in this report and in our Form 10-K, 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 - Divestiture Transactions and Discontinued Operations, Note 3 - Rate and Regulatory Matters, Note 9 - Related Party Transactions and Note 11 - Callaway Energy Center in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at March 31, 2013. 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
Missouri 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) First layer of coverage provides for $500 million in property damage, decontamination, premature decommissioning, and the second layer of coverage provides excess property insurance up to $2.25 billion for losses in excess of the $500 million primary coverage. Effective April 1, 2013, a $1.5 billion sub-limit was established for non-nuclear events.

(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. Effective April 1, 2013, non-nuclear events are sub-limited to $327.6 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 up to $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 9 - 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. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

At March 31, 2013, total other obligations related to the procurement of coal, natural gas, nuclear fuel, purchased power, methane gas, and equipment and meter reading services, among other agreements, at Ameren, Ameren Missouri and Ameren Illinois were $7,515 million, $5,151 million, and $2,316 million, respectively. Total unrecognized tax benefits at March 31, 2013, which were not included in the previous totals, for Ameren, Ameren Missouri and Ameren Illinois were $190 million, $126 million, and $4 million, respectively.

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 AER's coal-fired energy centers in Illinois, the EPA is developing 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 AER, 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 fine particulates, SO_2, and NO_x emissions; the CSAPR, which would have required further reductions of SO₂ emissions and NO_x emissions from energy centers; a regulation governing management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from energy centers; revised NSPS for particulate matter, SO₂, and NO_x emissions from new sources; new effluent standards applicable to discharges from steam-electric generating units; 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 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 AER. Compliance with these 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 tables 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 and the MATS as of March 31, 2013. In addition, the estimates assume that CCR will continue to be regarded as nonhazardous. The estimates do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures or the impact of the effluent standards applicable to steam-electric generating units that the EPA proposed in April 2013 as our evaluation of those impacts is ongoing. The estimates shown in the tables below could change significantly depending upon a variety of factors including:

• Ameren’s exit from the Merchant Generation business;

• 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 or new rules governing air pollutant transport;

• regulations under the Clean Water Act regarding cooling water intake structures or effluent standards;

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

• new limitations or standards under the Clean Water Act applicable to discharges from steam-electric generating units;

• new technology;

• expected power prices;

• variations in costs of material or labor; and

• alternative compliance strategies or investment decisions.

Continuing Operations:

	2013		2014 - 2017					2018 - 2022					Total
AMO(a)	$	105	$	215	-	$	260	$	795	-	$	975	$	1,115	-	$	1,340

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

Discontinued Operations:

	2013		2014 - 2017					2018 - 2022					Total
Genco(a)	30		100		-	125		220		-	270		350		-	425
AERG	5		20		-	25		20		-	25		45		-	55
Total(b)	$	35	$	120	-	$	150	$	240	-	$	295	$	395	-	$	480

(a) Includes estimated costs of approximately $20 million annually, excluding capitalized interest, from 2013 through 2017 for construction of two Newton energy center scrubbers.

(b) Assumes the Merchant Generation facilities are owned by Ameren.

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 SO₂ and NO_x emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO₂ and NO_x emissions (the CAIR). The CAIR 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 SO₂ emissions, annual NO_x emissions, and ozone season NO_x emissions.

In December 2008, the United States Court of Appeals for the District of Columbia Circuit 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. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR. In August 2012, the United States Court of Appeals for the District of Columbia Circuit 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 January 2013, the full Court of Appeals for the District of Columbia Circuit denied the EPA's request for rehearing. In March 2013, the EPA and certain environmental groups filed an appeal of the Circuit Court’s remand of CSAPR to the Supreme Court. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the decision to vacate the CSAPR is overturned by the United States Supreme Court.

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 in certain cases, emission compliance can be achieved by averaging emissions from similar electric generating units at the same 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 extensions to comply with the MATS by April 2016.

Separately, in December 2012, the EPA issued a final rule that made the national ambient air quality standard for fine particulate matter more stringent. States must develop control measures designed to reduce the emission of fine particulate matter below required levels to achieve compliance with the new standard. Such measures may or may not apply to energy centers but could require reductions in SO₂ and NO_x emissions. Compliance with the rule is required by 2020, or 2025 if an extension of time to achieve compliance is granted. Ameren Missouri and AER are currently evaluating the new standard while the states of Missouri and Illinois develop their attainment plans.

In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standards for ozone. The EPA is required to revisit these standards for ozones again in 2013. The states of Illinois and Missouri will be required to develop attainment plans to comply with the 2008 ambient air quality standards for ozone, which could result in additional emission control requirements for power plants by 2020. Ameren, Ameren Missouri and AER 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.

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 described below. The Illinois Pollution Control Board approved AER's proposed plan to restrict its SO₂ emissions through 2014 to levels lower than those previously required by the 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, or Ameren’s ability after the divestiture of New AER occurs, 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.

As a condition to IPH’s obligation to complete the acquisition of New AER, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS. AER and Dynegy filed a transfer request with the Illinois Pollution Control Board on May 2, 2013. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of AER.

Under the MPS, AER is required to reduce mercury, NO_x and SO₂ emissions with declining limits starting in 2009 for mercury and in 2010 for NO_x and SO_2..The final NO_x limit became effective in 2012. The final mercury limit will become effective in 2015 and the final SO₂ limit will become effective 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 installations and other pollution controls at some of AER's energy centers. To comply with the MPS and other air emissions laws and regulations, AER is installing equipment designed to reduce its emissions of mercury, NO_x, and SO₂. AER has installed three scrubbers at two energy centers. Two additional scrubbers are being constructed at the 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.

Environmental compliance costs could be prohibitive at some of Ameren's, Ameren Missouri's and AER'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 SO₂ emissions and created annual and ozone season NO_x allowances. Ameren and Ameren Missouri expect to have adequate CAIR allowances for 2013 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 rates for electricity and thereby household costs. 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 regulations could cause the conversion of coal-fired power plants to natural gas, or the construction of new natural gas plants to replace coal-fired power plants. As a result, economy wide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas.

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 issued 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 address 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 Circuit upheld the Tailoring Rule. Industry groups and a coalition of states filed petitions in April 2013 requesting that the United States Supreme Court review the circuit court’s decision upholding the Tailoring Rule.

Separately, in March 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 therefore does not affect any of the Ameren, Ameren Missouri or AER 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 2013. 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.

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 AER, 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 and Ameren Missouri'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 that CO₂ emissions from several industrial companies, including Ameren Missouri, Genco, and AERG, created 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, their impact on our coal-fired energy centers and our customers' costs is unknown, but they 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 DistrictCourt 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 the requirement to install 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 and Ameren Missouri. 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.

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% 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 a specified level. The proposed rule also requires existing power 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 AER 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 AER 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 April 2013, the EPA announced its proposal to revise the effluent limitation guidelines applicable to steam electric generating units under the Clean Water Act. Effluent limitation guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The proposed revision targets wastewater streams associated with fluegas desulfurization (i.e. scrubbers), fly ash, bottom ash, fluegas mercury control, CCR leachate from landfills and impoundments, nonchemical metal cleaning and gassification of fuels. The EPA’s proposal identifies several alternatives for addressing these waste streams, including best management practices for CCR impoundments.The EPA’s proposed rule raised several compliance options that would prohibit effluent discharges of certain, but not all, waste streams and impose more stringent limitations on certain components in wastewater discharges from power plants. If enacted as proposed, Ameren Missouri and AER would be subject to the revised limitations beginning July 1, 2017, but no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impact on our operations if enacted as proposed. The EPA expects to finalize the rule in 2014.

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.

As part of the transfer of generation assets by our rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003, Ameren Illinois’ predecessor companies contractually agreed to indemnify Genco and AERG for claims relating to pre-existing environmental conditions at the transferred sites. The plant transfer agreements between both Genco and Ameren Illinois and AERG and Ameren Illinois will be amended as part of the transaction agreement for Ameren to divest New AER to IPH. The agreements will specify that all environmental liabilities associated with the Meredosia and Hutsonville energy centers will be assumed by Medina Valley. The agreements will also specify that all environmental liabilities associated with Genco’s Newton and Coffeen energy centers and AERG’s E.D. Edwards and Duck Creek energy centers will no longer be indemnified by Ameren Illinois. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of New AER.

As of March 31, 2013, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois. These are in various stages of investigation, evaluation, remediation and closure. Based on current estimated plans, Ameren Illinois could substantially conclude remediation efforts at most of these sites by 2018. 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 March 31, 2013, Ameren Missouri has one remaining former MGP site for which remediation is scheduled. Remediation is complete at the other Ameren Missouri former MGP sites. Ameren Missouri does not currently have a rate rider mechanism that permits it to recover from utility customers remediation costs associated with MGP sites from utility customers.

The following table presents, as of March 31, 2013, the estimated probable obligation to remediate these former MGP sites.

	Estimate				Recorded   Liability(a)
	Low		High
Ameren	$	259	$	342	$	259
Ameren Missouri	5		6		5
Ameren Illinois	254		336		254

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

The scope and extent to which these former MGP sites are remediated may increase as remediation efforts continue. Considerable uncertainty remains in these estimates as many factors can influence the ultimate actual costs, including site specific unanticipated underground structures, the degree to which groundwater is encountered, regulatory changes, local ordinances and site accessibility. The actual costs may vary substantially from these estimates.

Ameren Illinois utilized an off-site landfill, which Ameren Illinois did not own, in connection with its operation of the Coffeen energy center prior to the formation of Genco. While not currently mandated, Ameren Illinois may be required to perform certain remediation activities associated with that landfill. As of March 31, 2013, Ameren Illinois estimated the obligation related to the cleanup 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 March 31, 2013, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.

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 March 31, 2013, 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 that this trust fund will be sufficient to complete the remaining adjacent off-site cleanup and it therefore has no recorded liability at March 31, 2013, for this site.

Ameren Missouri also has a federal agency mandate to complete an 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 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 2013. 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 Sauget Area 2. As of March 31, 2013, Ameren Missouri estimated its obligation related to Sauget Area 2 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.

In December 2012, Ameren Missouri signed an administrative order with the EPA and agreed to investigate soil and groundwater conditions at an Ameren Missouri owned substation in St. Charles, Missouri. As of March 31, 2013, Ameren Missouri estimated the obligation related to the cleanup at $1.7 million to $4.5 million. Ameren Missouri recorded a liability of $1.7 million to represent its estimated minimum obligation for this site, 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 laws. We are unable to determine whether such practices will result in future environmental commitments or will 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. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric generating units would apply to ash pond and CCR management and intended to align this proposal with the CCR rules proposed in May 2010. 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 AER 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 AER 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.

The Illinois EPA has issued violation notices with respect to groundwater conditions existing at Genco’s ash pond systems. In April 2013, AER filed a proposed rulemaking with the Illinois Pollution Control Board which, if approved, would provide for the systematic and eventual closure of ash ponds. The rulemaking process could take up to two years to complete. Genco and AERG changed their ARO fair value estimates relating to their ash ponds to revise their expected retirement dates.

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 March 31, 2013, Ameren Missouri had an insurance receivable balance of $68 million. Ameren Missouri's results of operations, financial position and liquidity could be adversely affected if its remaining liability insurance claims are not paid by insurers.

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 that the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting 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 appealed the January 2011 ruling to the United States Court of Appeals for the Eighth Circuit. 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 second insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the April 2012 litigation, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In an April 2013 ruling, the United States Court of Appeals for the Eighth Circuit affirmed the denial by the United States District Court for the Eastern District of Missouri of the insurer's motion to require arbitration.

Asbestos-related Litigation

Ameren, Ameren Missouri, and Ameren Illinois 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 the average number of parties being 80 as of March 31, 2013. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.

The claims filed against Ameren, Ameren Missouri and Ameren Illinois allege injury from asbestos exposure during the plaintiffs' activities at our present or former energy centers.

Former CIPS energy centers are now owned by Genco, and former CILCO energy centers are now owned by AERG. As a condition to transferring ownership of the CIPS and CILCO energy centers, CIPS and CILCO, now Ameren Illinois, contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising or existing from activities prior to the transfer. The plant transfer agreement between Genco and Ameren Illinois and the plant transfer agreement between AERG and Ameren Illinois each will be amended pursuant to the transaction agreement in which Ameren agrees to divest New AER to IPH. The amended plant transfer agreements will provide that Ameren Illinois will continue to retain asbestos exposure related liabilities for claims arising or existing from activities prior to the transfer of the ownership of the CIPS and CILCO energy centers to Genco and AERG. IPH will be responsible for any asbestos-related claims arising from activities that occur after it takes ownership of New AER. Any asbestos-related claims arising solely from activities post transfer of the energy centers from CIPS and CILCO to Genco and AERG, respectively, but prior to IPH taking ownership of New AER, of which there are currently none, will be retained by Ameren.See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren's divestiture of AER.

The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of March 31, 2013:

Ameren	Ameren Missouri	Ameren Illinois	Total(a)
3	66	81	103

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

At March 31, 2013, Ameren, Ameren Missouri and Ameren Illinois had liabilities of $19 million, $8 million, and $11 million, respectively, recorded to represent their best estimate of their obligations related to asbestos claims.

Ameren Illinois has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are to be recovered from a trust fund that was established when Ameren acquired IP. At March 31, 2013, 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. Following the Ameren Illinois Merger, this rider is applicable only for claims that occurred within IP’s historical service territory. Similarly, the rider will permit recovery only from customers within IP’s historical service territory.

Ameren Illinois Municipal Taxes

Ameren Illinois received tax liability notices from the city of O'Fallon, Illinois relating to prior-period electric and natural gas municipal taxes. The city alleges that Ameren Illinois failed to collect prior-period taxes from more than 2,100 local resident addresses primarily innewly annexed areas for the period 2005 through 2010. Ameren Illinois is challenging the city's position on this matter. Ameren Illinois believes its defenses to the notices of tax liability are meritorious and will defend itself vigorously. As of March 31, 2013, Ameren Illinois did not believe it was probable that the city of O'Fallon would prevail and therefore has not recorded a charge to earnings for a loss contingency related to this matter.  Should Ameren Illinois ultimately be found liable for these prior-period municipal taxes, the amount is estimated between $2 million and $4 million, including interest and penalties. In addition, at the end of 2012, the city of O'Fallon and six other cities issued tax liability notices alleging that Ameren Illinois failed to collect prior-period taxes from certain local resident addresses. At this time, it is premature in Ameren Illinois' review of the additional notices received at the end of 2012 to reasonably estimate any likelihood of loss.

Illinois Sales and Use Tax Exemptions and Credits

In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear 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 casethat electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. In November 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 does not believe that it is probable that the state of Illinois will prevail and therefore has not recorded a charge to earnings for the loss contingency. From the second quarter of 2010 through December 31, 2011, Ameren claimed manufacturing exemptions and credits of $27 million, which represents the maximum potential tax liability to Ameren, excluding any penalties assessed or interest accrued.

Genco, including EEI, and AERG did not claim any additional manufacturing exemptions or credits in 2012 and do not anticipate claiming any additional manufacturing exemptions or credits in 2013, pending discussions with the Illinois Department of Revenue. Each company, however, is reserving the right to apply for applicable refunds at a later date.

Ameren will retain responsibility for this contingent liability after the divestiture of New AER is completed.

Medina Valley Asset Sale

In February 2012, Ameren completed the sale of the Medina Valley energy center’s net property and plant for cash proceeds of $16 million and an additional $1 million to be paid at the two-year anniversary date of the sale if all terms of the sale agreement were met. Ameren recognized a $10 million pretax gain 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. During the first quarter of 2013, Ameren concluded it was no longer probable it will receive the additional $1 million associated with this sale and therefore expensed the receivable amount.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2013	Apr. 30, 2013
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Trading Symbol	AEE
Entity Registrant Name	AMEREN CORP
Entity Central Index Key	0001002910
Current Fiscal Year End Date	--03-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		242,634,671
Union Electric Company [Member]
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Entity Registrant Name	UNION ELECTRIC CO
Entity Central Index Key	0000100826
Current Fiscal Year End Date	--03-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		102,123,834
Ameren Illinois Company [Member]
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Entity Registrant Name	AMEREN ILLINOIS CO
Entity Central Index Key	0000018654
Current Fiscal Year End Date	--03-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		25,452,373

XML

Callaway Energy Center

3 Months Ended

Mar. 31, 2013

Nuclear Waste Matters [Abstract]

CALLAWAY ENERGY CENTER

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 energy centers. Under the NWPA, Ameren and other companies that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established the fee that these companies pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatthour 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 companies 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 standard contract, Ameren Missouri collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway energy center.

Both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, however, no federal storage facility currently exists. 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 federal government 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 companies’ 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.

In January 2013, the DOE issued its plan for the management and disposal of spent nuclear fuel in response to the recommendation contained in the advisory commission's report. The DOE's plan calls for a pilot interim storage facility to begin operation with an initial focus on accepting spent nuclear fuel from shutdown reactor sites by 2021. By 2025, a larger interim storage facility would be available and would be co-located with the pilot facility. The plan also proposes to site a permanent geological repository to begin operation by 2048. 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 spent nuclear fuel from nuclear energy centers and fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners have sued the DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed a breach of contract lawsuit to recover costs that it incurred through 2009. This amount included the cost of reracking the Callaway energy center’s spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes that Ameren Missouri would not have incurred had DOE performed its contractual obligations. In June 2011, the parties reached a settlement that included an annual reimbursement of Ameren Missouri’s spent fuel storage and related costs through at least 2013. In March 2013, Ameren Missouri submitted its 2012 costs to the DOE for reimbursement under the settlement agreement. Ameren Missouri expects to receive the 2012 cost reimbursement of $6 million during the third quarter of 2013.

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 deadline by which the NRC must act on this application. Among the rules that the NRC has historically relied upon in 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 energy center 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 2016.

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 2012, 2011, and 2010. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway energy center. Electric rates may be adjusted at such times to reflect changed estimates. If Ameren Missouri's operating license extension application is approved by the NRC, a revised funding analysis will be prepared and the rates charged to customers will be adjusted accordingly to reflect the operating license extension at the time of the next triennial cost study and funding analysis is approved by the MoPSC. 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 sheets. 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 3 - Rate and Regulatory Matters for additional information related to the Callaway energy center.

XML

Consolidated Statement of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Net Income from Continuing Operations	$ 56	$ 39
Other Comprehensive Income, Net of Taxes	0	0
Comprehensive Income from Continuing Operations	56	39
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests	2	2
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation	54	37
Net Loss from Discontinued Operations	(199)	(442)
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Taxes	(7)	15
Comprehensive Loss from Discontinued Operations	(206)	(427)
Less: Comprehensive Loss from Discontinued Operations Attributable to Noncontrolling Interest	0	(2)
Comprehensive Loss from Discontinued Operations Attributable to Ameren Corporation	(206)	(425)
Comprehensive Income (Loss)	$ (152)	$ (388)

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Long-Term Debt And Equity Financings

3 Months Ended

Mar. 31, 2013

Long-Term Debt And Equity Financings [Abstract]

LONG-TERM DEBT AND EQUITY FINANCINGS

LONG-TERM DEBT AND EQUITY FINANCINGS

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. 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 as of March 31, 2013, 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	4.7	$	4,304		≥2.5	128.1	$	2,454
Ameren Illinois	≥2.0	7.2		3,499	(d)	≥1.5	2.7		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.

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 2012 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 and Ameren Illinois and certain other 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 dividend payments on its 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 March 31, 2013, Ameren Illinois’ ratio of common stock equity to total capitalization was 57%.

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.

Off-Balance-Sheet Arrangements

At March 31, 2013, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

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Short-Term Debt And Liquidity

3 Months Ended

Mar. 31, 2013

Line of Credit Facility [Abstract]

SHORT-TERM DEBT AND LIQUIDITY

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 agreements, or commercial paper issuances.

The 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement were not utilized for borrowings during the three months ended March 31, 2013. As of March 31, 2013, based on letters of credit issued under the 2012 Credit Agreements, the aggregate amount of credit capacity available to Ameren (parent), Ameren Missouri and Ameren Illinois, collectively at March 31, 2013, was $2.06 billion.

Commercial Paper

Ameren did not have any commercial paper outstanding at March 31, 2013, or December 31, 2012. The average daily commercial paper balances outstanding during the three months ended March 31, 2013, and 2012, were $2 million and $84 million, respectively. The weighted-average interest rates during the three months ended March 31, 2013, and 2012, were 0.80% and 0.94%, respectively. The peak short-term commercial paper balances outstanding during the three months ended March 31, 2013, and 2012, were $21 million and $186 million, respectively. The peak interest rates during the three months ended March 31, 2013, and 2012, were 0.85% and 1.25%, respectively. Ameren Missouri and Ameren Illinois did not utilize their commercial paper programs during the three months ended March 31, 2013, and 2012.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants within the 2012 Credit Agreements. See Note 4 – Short-term Debt and Liquidity in the Form 10-K for a detailed description of these provisions.

The 2012 Credit Agreements 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 2012 Credit Agreements require each of Ameren, Ameren Missouri and Ameren Illinois to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of March 31, 2013, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2012 Credit Agreements, were 52%, 48% and 42%, for Ameren, Ameren Missouri and Ameren Illinois, respectively. In addition, under the 2012 Illinois Credit Agreement and by virtue of the cross-default provisions of the 2012 Missouri 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 2012 Illinois Credit Agreement. Ameren’s ratio as of March 31, 2013, was 5.1 to 1.0. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2012 Credit Agreement. Ameren’s ratios, as discussed above, include both continuing and discontinued operations for the purposes of these calculations.

None of the Ameren Companies' credit agreements or financing arrangements contain credit rating triggers that would cause a 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 agreements at March 31, 2013.

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 2012 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 months ended March 31, 2013, was 0.11% (2012 - 0.11%).

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 2012 Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. AER, Genco, AERG and Marketing Company may participate in the non-state-regulated money pool through the closing of the divestiture transaction as detailed in Note 2 - Divestiture Transactions and Discontinued Operations. 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 months ended March 31, 2013, was 0.22% (2012 - 0.76%).

See Note 9 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three months ended March 31, 2013, and 2012.

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Divestiture Transactions and Discontinued Operations (Tables)

3 Months Ended

Mar. 31, 2013

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

The following table presents the components of discontinued operations in Ameren's consolidated statement of income (loss) for the three months ended March 31, 2013, and 2012:

	Three Months
	2013				2012
Operating revenues	$	264			$	246
Operating expenses	(415		)	(a)	(826		)	(b)
Operating (loss)	(151		)		(580		)
Other income (loss)	(2		)		—
Interest charges	(11		)		(15		)
Loss before income taxes	(164		)		(595		)
Income tax (expense) benefit	(35		)		153
Loss from discontinued operations, net of taxes	$	(199	)		$	(442	)

(a) Includes a noncash pretax impairment charge of $155 million to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell.

(b) Includes 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 under held and used accounting guidance.

The following table presents the carrying amounts of the components of assets and liabilities segregated on Ameren's consolidated balance sheets as discontinued operations at March 31, 2013, and December 31, 2012:

	March 31, 2013		December 31, 2012
Current assets of discontinued operations
Cash and cash equivalents	$	25	$	25
Accounts receivable and unbilled revenue	103		102
Materials and supplies	117		134
Mark-to-market derivative assets	101		102
Property and plant, net	607		748
Accumulated deferred income taxes, net	412		373
Other assets	135		116
Total current assets of discontinued operations	$	1,500	$	1,600
Current liabilities of discontinued operations
Accounts payable and other current obligations	$	138	$	133
Mark-to-market derivative liabilities	82		63
Long-term debt, net	824		824
Asset retirement obligations	86		78
Pension and other postretirement benefits	39		40
Other liabilities	29		28
Total current liabilities of discontinued operations	$	1,198	$	1,166
Accumulated other comprehensive gain(a)	$	12	$	19
Noncontrolling interest(b)	$	8	$	8

(a) Accumulated other comprehensive gain related to discontinued operations remains in “Accumulated other comprehensive gain (loss)” on Ameren’s March 31, 2013, and December 31, 2012, balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s balance sheet either before or at the closing of the New AER divestiture.

(b) The 20% ownership interest of EEI not owned by Ameren remains in “Noncontrolling interests” on Ameren’s March 31, 2013, and December 31, 2012, balance sheets. This noncontrolling interest will be removed from Ameren’s balance sheet at the closing of the New AER divestiture.

Schedule Of Coverage Ratios

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. 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 as of March 31, 2013, 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	4.7	$	4,304		≥2.5	128.1	$	2,454
Ameren Illinois	≥2.0	7.2		3,499	(d)	≥1.5	2.7		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 requir

Ameren Energy Generating Company [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Schedule Of Coverage Ratios

Genco Indenture Provisions

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 March 31, 2013:

	Required Ratio	Actual Ratio
Restricted payment interest coverage ratio(a)	≥1.75	2.3
Additional indebtedness interest coverage ratio(b)	≥2.50	2.3
Additional indebtedness debt-to-capital ratio(b)	≤60%	50	%

(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 consider

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Retirement Benefits

3 Months Ended

Mar. 31, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

RETIREMENT BENEFITS

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 March 31, 2013, its estimated investment performance through March 31, 2013, and its pension funding policy, Ameren expects to make annual contributions of $60 million to $150 million in each of the next five years, with aggregate estimated contributions of $550 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’s beneficiary association (VEBA) trusts to match the annual postretirement expense.

The following table presents the components of the net periodic benefit cost for Ameren’s pension and postretirement benefit plans for the three months ended March 31, 2013, and 2012:

	Pension Benefits						Postretirement Benefits
	Three Months						Three Months
	2013			2012			2013			2012
Service cost	$	24		$	21		$	6		$	6
Interest cost	40			42			12			13
Expected return on plan assets	(54		)	(52		)	(16		)	(14		)
Amortization of:
Prior service cost (benefit)	(1		)	(1		)	(1		)	(1		)
Actuarial loss	22			19			2			3
Net periodic benefit cost	$	31		$	29		$	3		$	7

Ameren Missouri and Ameren Illinois are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three months ended March 31, 2013, and 2012:

	Pension Costs				Postretirement Costs
	Three Months				Three Months
	2013		2012		2013		2012
Ameren Missouri	$	18	$	16	$	2	$	5
Ameren Illinois	10		10		1		2
Other	3		3		—		—
Ameren(a)	$	31	$	29	$	3	$	7

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

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Fair Value Measurements

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

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, United States 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 United States 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. 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. 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 three months ended March 31, 2013:

		Fair Value								Weighted
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Average
Level 3 Derivative asset and liability - commodity contracts(a):
Ameren	Fuel oils	$	7	$	(2	)	Discounted cash flow	Escalation rate(%)(b)	.20 - .59	.39
								Counterparty credit risk(%)(c)(d)	.26 - 3	1
							Option model	Volatilities(%)(b)	10 - 19	17
	Natural gas	3		(1		)	Option model	Escalation rate(%)(b)	.20 - .46	.37
								Nodal basis($/mmbtu)(c)	(.24) - (.04)	(.19)
							Discounted cash flow	Escalation rate(%)(b)	.20 - .46	.35
								Nodal basis($/mmbtu)(c)	(.18) - 0	(.01)
								Counterparty credit risk(%)(c)(d)	.26 - 5	1
								Ameren credit risk(%)(c)(d)	2 - 3	3
	Power(e)	12		(91		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)	24 - 48	33
								Estimated auction price for FTRs($/MW)(b)	0 - 4,280	190
								Nodal basis($/MWh)(c)	(5) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	.22 - 5	2
								Ameren credit risk(%)(c)(d)	2 - 3	3
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	5 - 7	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)(d)	5 - 7	6
	Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	42 - 45	43
Ameren Missouri	Fuel oils	$	7	$	(2	)	Discounted cash flow	Escalation rate(%)(b)	.20 - .59	.39
								Counterparty credit risk(%)(c)(d)	.26 - 3	1
							Option model	Volatilities(%)(b)	10 - 19	17
	Natural gas	1		(1		)	Option model	Escalation rate(%)(b)	.20 - .46	.37
								Nodal basis($/mmbtu)(c)	(.24) - (.04)	(.19)
							Discounted cash flow	Escalation rate(%)(b)	.20 - .46	.26
								Nodal basis($/mmbtu)(c)	(.18) - (.02)	(.04)
								Counterparty credit risk(%)(c)(d)	.26 - 5	1
								Ameren Missouri credit risk(%)(c)(d)	2	(f)
	Power(e)	9		(7		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)	24 - 51	38
								Estimated auction price for FTRs($/MW)(b)	0 - 4,280	190
								Nodal basis($/MWh)(c)	(5) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	.22 - 5	1
								Ameren Missouri credit risk(%)(c)(d)	2	(f)
	Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	42 - 45	43
Ameren Illinois	Natural gas	$	2	$	—		Discounted cash flow	Escalation rate(%)(b)	.20 - .46	.33
								Nodal basis($/mmbtu)(c)	(.05) - 0	—
								Counterparty credit risk(%)(c)(d)	.70 - 2	1
								Ameren Illinois credit risk(%)(c)(d)	3	(f)
	Power(e)	3		(84		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(b)	24 - 42	32
								Nodal basis($/MWh)(b)	(4) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	2	(f)
								Ameren Illinois credit risk(%)(c)(d)	3	(f)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	5 - 7	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6

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

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

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

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

(e) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand.

(f) Not applicable.

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 twelve-month period ended December 31, 2012:

		Fair Value								Weighted
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Average
Level 3 Derivative asset and liability - commodity contracts(a):
Ameren	Fuel oils	$	8	$	(3	)	Discounted cash flow	Escalation rate(%)(b)	.21 - .60	.44
								Counterparty credit risk(%)(c)(d)	.12 - 1	1
								Ameren credit risk(%)(c)(d)	2	(e)
							Option model	Volatilities(%)(b)	7 - 27	24
	Power(f)	14		(114		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)	22 - 47	31
								Estimated auction price for FTRs($/MW)(b)	(281) - 1,851	178
								Nodal basis($/MWh)(c)	(5) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	.22 - 1	1
								Ameren credit risk(%)(c)(d)	2 - 5	5
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 8	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6
	Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	43 - 46	44
Ameren Missouri	Fuel oils	$	8	$	(3	)	Discounted cash flow	Escalation rate(%)(b)	.21 - .60	.44
								Counterparty credit risk(%)(c)(d)	.12 - 1	1
								Ameren Missouri credit risk(%)(c)(d)	2	(e)
							Option model	Volatilities(%)(b)	7 - 27	24
	Power(f)	14		(3		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)	24 - 56	36
								Estimated auction price for FTRs($/MW)(b)	(281) - 1,851	178
								Nodal basis($/MWh)(c)	(5) - (1)	(2)
								Counterparty credit risk(%)(c)(d)	.22 - 1	1
								Ameren Missouri credit risk(%)(c)(d)	2
	Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	43 - 46	44
Ameren Illinois	Power(f)	$	—	$	(111	)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(b)	22 - 47	30
								Nodal basis($/MWh)(b)	(5) - (1)	(3)
								Ameren Illinois credit risk(%)(c)(d)	5	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 8	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6

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

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

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

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

(e) Not applicable.

(f) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand.

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 no gains or losses in the first three months of 2013 or 2012 related to valuation adjustments for counterparty default risk. At March 31, 2013, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $1 million, less than $1 million, and $1 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. At December 31, 2012, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $7 million, less than $1 million, and $7 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively.

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of March 31, 2013:

		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	Derivative assets - commodity contracts(a):
	Fuel oils	$	3	$	—	$	7	$	10
	Natural gas	1		4		3		8
	Power	—		7		12		19
	Total derivative assets - commodity contracts	$	4	$	11	$	22	$	37
	Nuclear Decommissioning Trust Fund(b):
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	294		—		—		294
	Debt securities:
	Corporate bonds	—		48		—		48
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		77		—		77
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	296	$	138	$	—	$	434
	Total Ameren	$	300	$	149	$	22	$	471
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	3	$	—	$	7	$	10
	Natural gas	—		1		1		2
	Power	—		7		9		16
	Total derivative assets - commodity contracts	$	3	$	8	$	17	$	28
	Nuclear Decommissioning Trust Fund(b):
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	294		—		—		294
	Debt securities:
	Corporate bonds	—		48		—		48
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		77		—		77
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	296	$	138	$	—	$	434
	Total Ameren Missouri	$	299	$	146	$	17	$	462
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	1	$	3	$	2	$	6
	Power	—		—		3		3
	Total Ameren Illinois	$	1	$	3	$	5	$	9
Liabilities:
Ameren	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	1	$	—	$	2	$	3
	Natural gas	5		73		1		79
	Power	—		8		91		99
	Uranium	—		—		2		2
	Total Ameren	$	6	$	81	$	96	$	183
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	1	$	—	$	2	$	3
	Natural gas	5		6		1		12
	Power	—		8		7		15
	Uranium	—		—		2		2
	Total Ameren Missouri	$	6	$	14	$	12	$	32
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	67	$	—	$	67
	Power	—		—		84		84
	Total Ameren Illinois	$	—	$	67	$	84	$	151

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

(b) Balance excludes $3 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, 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	Derivative assets - commodity contracts(a):
	Fuel oils	$	4	$	—	$	8	$	12
	Natural gas	—		2		—		2
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	4	$	3	$	22	$	29
	Nuclear Decommissioning Trust Fund(b):
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	264		—		—		264
	Debt securities:
	Corporate bonds	—		47		—		47
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		81		—		81
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	265	$	141	$	—	$	406
	Total Ameren	$	269	$	144	$	22	$	435
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	4	$	—	$	8	$	12
	Natural gas	—		1		—		1
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	4	$	2	$	22	$	28
	Nuclear Decommissioning Trust Fund(b):
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	264		—		—		264
	Debt securities:
	Corporate bonds	—		47		—		47
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		81		—		81
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	265	$	141	$	—	$	406
	Total Ameren Missouri	$	269	$	143	$	22	$	434
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	—	$	1	$	—	$	1
	Power	—		—		—		—
	Total Ameren Illinois	$	—	$	1	$	—	$	1

		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	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	1	$	—	$	3	$	4
	Natural gas	7		102		—		109
	Power	—		1		114		115
	Uranium	—		—		2		2
	Total Ameren	$	8	$	103	$	119	$	230
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	1	$	—	$	3	$	4
	Natural gas	7		8		—		15
	Power	—		1		3		4
	Uranium	—		—		2		2
	Total Ameren Missouri	$	8	$	9	$	8	$	25
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	94	$	—	$	94
	Power	—		—		111		111
	Total Ameren Illinois	$	—	$	94	$	111	$	205

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

(b) Balance excludes $2 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 March 31, 2013:

		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2013	$	5		$	(a)		$	5
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—			(a)			—
Total realized and unrealized gains (losses)		—			(a)			—
Purchases		1			(a)			1
Sales		—			(a)			—
Settlements		(1	)		(a)			(1	)
Ending balance at March 31, 2013	$	5		$	(a)		$	5
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2013	$	—		$	(a)		$	—
Natural gas:
Beginning balance at January 1, 2013	$	—		$	—		$	—
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—			1			1
Total realized and unrealized gains (losses)		—			1			1
Purchases		—			1			1
Ending balance at March 31, 2013	$	—		$	2		$	2
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2013	$	—		$	—		$	—
Power:
Beginning balance at January 1, 2013	$	11		$	(111	)	$	(100	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		5			14			19
Total realized and unrealized gains (losses)		5			14			19
Settlements		(13	)		16			3
Transfers into Level 3		(2	)		—			(2	)
Transfers out of Level 3		1			—			1
Ending balance at March 31, 2013	$	2		$	(81	)	$	(79	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2013	$	(3	)	$	14		$	11
Uranium:
Beginning balance at January 1, 2013	$	(2	)	$	(a)		$	(2	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—			(a)			—
Total realized and unrealized gains (losses)		—			(a)			—
Ending balance at March 31, 2013	$	(2	)	$	(a)		$	(2	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2013	$	—		$	(a)		$	—

(a) Not applicable.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2012:

		Net derivative commodity contracts
		Ameren Missouri				Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2012	$	3			$	(a)		$	3
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		2				(a)			2
Total realized and unrealized gains (losses)		2				(a)			2
Transfers into Level 3		2				(a)			2
Ending balance at March 31, 2012	$	7			$	(a)		$	7
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012	$	2			$	(a)		$	2
Natural gas:
Beginning balance at January 1, 2012	$	(14		)	$	(160	)	$	(174		)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(2		)		(26	)		(28		)
Total realized and unrealized gains (losses)		(2		)		(26	)		(28		)
Settlements		1				16			17
Transfers out of Level 3		15				170			185
Ending balance at March 31, 2012	$	—			$	—		$	—
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012	$	—			$	—		$	—
Power(b):
Beginning balance at January 1, 2012	$	21			$	(140	)	$	81
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		13				(220	)		(158		)
Total realized and unrealized gains (losses)		13				(220	)		(158		)
Settlements		(13		)		76			(4		)
Transfers out of Level 3		(1		)		—			(1		)
Ending balance at March 31, 2012	$	20			$	(284	)	$	(82		)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012	$	10			$	(202	)	(c) $	(156		)
Uranium:
Beginning balance at January 1, 2012		$	(1	)		(a)			$	(1	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—				(a)			—
Total realized and unrealized gains (losses)		—				(a)			—
Ending balance at March 31, 2012		$	(1	)		(a)			$	(1	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012		$	—			(a)			$	—

(a) Not applicable.

(b) Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company.

(c) 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.

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 March 31, 2013, and the previous reporting period ended December 31, 2012. 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 months ended March 31, 2013, and 2012, 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 months ended March 31, 2013, and 2012:

	2013			2012
Ameren - 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	—			185
Transfers into Level 3 / Transfers out of Level 2 - Power	(2		)	—
Transfers out of Level 3 / Transfers into Level 2 - Power	1			(1		)
Net fair value of Level 3 transfers	$	(1	)	$	186
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	(2		)	—
Transfers out of Level 3 / Transfers into Level 2 - Power	1			(1		)
Net fair value of Level 3 transfers	$	(1	)	$	16
Ameren Illinois - derivative commodity contracts:
Transfers out of Level 3 / Transfers into Level 2 - Natural gas	$	—		$	170

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. Ameren’s and Ameren Missouri’s carrying amounts of investments in debt securities related to the two CTs from the city of Bowling Green and Audrain County approximate fair value. These investments are classified as held-to-maturity. These investments are considered Level 2 in the fair value hierarchy as they are valued based on similar market transactions. Short-term borrowings for Ameren Missouri and Ameren Illinois 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 March 31, 2013, and December 31, 2012:

	March 31, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:(a)(b)
Long-term debt and capital lease obligations (including current portion)	$	6,158	$	7,127	$	6,157	$	7,110
Preferred stock	142		124		142		123
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	4,006	$	4,645	$	4,006	$	4,625
Preferred stock	80		74		80		73
Ameren Illinois:
Long-term debt (including current portion)	$	1,727	$	2,027	$	1,727	$	2,020
Preferred stock	62		50		62		49

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

(b) Preferred stock along with the noncontrolling interest of EEI is recorded in “Noncontrolling Interests” on the balance sheet.

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Fair Value Measurements (Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level Three In The Fair Value Hierarchy) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012		Jun. 30, 2012
Power [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ (100)	$ 81	[1]
Included in regulatory assets/liabilities	19	(158)	[1]
Total realized and unrealized gains (losses)	19	(158)	[1]
Settlements	3	(4)	[1]
Transfers into Level 3	(2)
Transfer out of Level 3	1	(1)	[1]
Ending balance	(79)	(82)	[1]
Change in unrealized gains (losses) related to assets/liabilities held at period end	11	(156)	[1]
Fuel Oils [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	5	3
Included in regulatory assets/liabilities		2
Total realized and unrealized gains (losses)		2
Purchases	1
Sales
Settlements	(1)
Transfers into Level 3		2
Ending balance	5	7
Change in unrealized gains (losses) related to assets/liabilities held at period end		2
Uranium [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(2)	(1)
Included in regulatory assets/liabilities
Total realized and unrealized gains (losses)
Ending balance	(2)	(1)
Change in unrealized gains (losses) related to assets/liabilities held at period end
Natural Gas [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance		(174)
Included in regulatory assets/liabilities	1	(28)
Total realized and unrealized gains (losses)	1	(28)
Purchases	1
Settlements		17
Transfer out of Level 3		185
Ending balance	2
Change in unrealized gains (losses) related to assets/liabilities held at period end
Union Electric Company [Member] | Power [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	11	21	[1]
Included in regulatory assets/liabilities	5	13	[1]
Total realized and unrealized gains (losses)	5	13	[1]
Settlements	(13)	(13)	[1]
Transfers into Level 3	(2)
Transfer out of Level 3	1	(1)	[1]
Ending balance	2	20	[1]
Change in unrealized gains (losses) related to assets/liabilities held at period end	(3)	10	[1]
Union Electric Company [Member] | Fuel Oils [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	5	3
Included in regulatory assets/liabilities		2
Total realized and unrealized gains (losses)		2
Purchases	1
Sales
Settlements	(1)
Transfers into Level 3		2
Ending balance	5	7
Change in unrealized gains (losses) related to assets/liabilities held at period end		2
Union Electric Company [Member] | Uranium [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(2)	(1)
Included in regulatory assets/liabilities
Total realized and unrealized gains (losses)
Ending balance	(2)	(1)
Change in unrealized gains (losses) related to assets/liabilities held at period end
Union Electric Company [Member] | Natural Gas [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance		(14)
Included in regulatory assets/liabilities		(2)
Total realized and unrealized gains (losses)		(2)
Purchases
Settlements		1
Transfer out of Level 3		15
Ending balance
Change in unrealized gains (losses) related to assets/liabilities held at period end
Ameren Illinois Company [Member] | Power [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(111)	(140)	[1]
Included in regulatory assets/liabilities	14	(220)	[1]
Total realized and unrealized gains (losses)	14	(220)	[1]
Settlements	16	76	[1]
Transfers into Level 3
Transfer out of Level 3			[1]
Ending balance	(81)	(284)	[1]
Change in unrealized gains (losses) related to assets/liabilities held at period end	14	(202)	[1],[2]
Ameren Illinois Company [Member] | Natural Gas [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance		(160)
Included in regulatory assets/liabilities	1	(26)
Total realized and unrealized gains (losses)	1	(26)
Purchases	1
Settlements		16
Transfer out of Level 3		170
Ending balance	2
Change in unrealized gains (losses) related to assets/liabilities held at period end

[1] Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company.

[2] 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.

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Other Income and Expenses

3 Months Ended

Mar. 31, 2013

Other Nonoperating Income (Expense) [Abstract]

OTHER INCOME AND EXPENSES

OTHER INCOME AND EXPENSES

The following table presents the components of “Other Income and Expenses” in the Ameren Companies’ statements of income (loss) for the three months ended March 31, 2013, and 2012:

	Three Months
	2013		2012
Ameren:(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	8	$	9
Interest income on industrial development revenue bonds	7		7
Other	—		1
Total miscellaneous income	$	15	$	17
Miscellaneous expense:
Donations	$	4	$	12	(b)
Other	4		3
Total miscellaneous expense	$	8	$	15
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	7	$	8
Interest income on industrial development revenue bonds	7		7
Total miscellaneous income	$	14	$	15
Miscellaneous expense:
Donations	$	2	$	2
Other	3		1
Total miscellaneous expense	$	5	$	3
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	1	$	1
Total miscellaneous income	$	1	$	1
Miscellaneous expense:
Donations	$	3	$	10	(b)
Other	—		1
Total miscellaneous expense	$	3	$	11

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

(b) Includes Ameren Illinois’ one-time $7.5 million donation to the Illinois Science and Energy Innovation Trust pursuant to the IEIMA as a result of Ameren Illinois’ 2012 participation in the formula ratemaking process.

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Derivative Financial Instruments

3 Months Ended

Mar. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE FINANCIAL INSTRUMENTS

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 March 31, 2013, and December 31, 2012:

	Quantity (in millions, except as indicated)
Commodity	Accrual & NPNS Contracts(a)		Other Derivatives(b)		Derivatives That Qualify for Regulatory Deferral(c)
	2013	2012	2013	2012	2013	2012
Coal (in tons)
Ameren Missouri & Ameren	91	96	(d)	(d)	(d)	(d)
Fuel oils (in gallons)(e)
Ameren Missouri & Ameren	(d)	(d)	(d)	(d)	67	26
Natural gas (in mmbtu)
Ameren Missouri	3	4	1	—	21	19
Ameren Illinois	12	16	(d)	(d)	137	128
Ameren	15	20	1	—	158	147
Power (in megawatthours)
Ameren Missouri	4	3	2	2	8	9
Ameren Illinois	19	21	(d)	(d)	12	14
Ameren	23	24	2	2	20	23
Renewable energy credits(f)
Ameren Missouri	3	3	(d)	(d)	(d)	(d)
Ameren Illinois	12	12	(d)	(d)	(d)	(d)
Ameren	15	15	(d)	(d)	(d)	(d)
Uranium (pounds in thousands)
Ameren Missouri & Ameren	4,950	5,142	(d)	(d)	480	446

(a) Accrual contracts include commodity contracts that do not qualify as derivatives. As of March 31, 2013, these contracts ran through December 2017, March 2015, September 2024, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively.

(b) As of March 31, 2013, these contracts ran through April 2013 and December 2014 for natural gas and power, respectively.

(c) As of March 31, 2013, these contracts ran through October 2015, March 2017, May 2032, and September 2014 for fuel oils, natural gas, power, and uranium, respectively.

(d) Not applicable.

(e) Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.

(f) A renewable energy credit is created for every one megawatthour of renewable energy generated. The Ameren Companies’ contracts include renewable energy credits from solar and wind-generated power.

Authoritative accounting 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 8 - 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 (loss) 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 (loss) 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 (loss) 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.

The following table presents the carrying value and balance sheet location of all derivative instruments as of March 31, 2013, and December 31, 2012:

	Balance Sheet Location		Ameren		Ameren Missouri		Ameren Illinois
2013
Derivative assets not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	MTM derivative assets	$	6	$	(b)	$	(b)
	Other current assets		—		6		—
	Other assets		4		4		—
Natural gas	MTM derivative assets		6		(b)		(b)
	Other current assets		—		1		5
	Other assets		2		1		1
Power	MTM derivative assets		15		(b)		(b)
	Other current assets		—		15		—
	Other assets		4		1		3
	Total assets	$	37	$	28	$	9
Derivative liabilities not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	MTM derivative liabilities	$	1	$	(b)	$	—
	Other current liabilities		—		1		—
	Other deferred credits and liabilities		2		2		—
Natural gas	MTM derivative liabilities		45		(b)		38
	Other current liabilities		—		7		—
	Other deferred credits and liabilities		34		5		29
Power	MTM derivative liabilities		25		(b)		11
	Other current liabilities		—		14		—
	Other deferred credits and liabilities		74		1		73
Uranium	MTM derivative liabilities		2		(b)		—
	Other current liabilities		—		2		—
	Total liabilities	$	183	$	32	$	151
2012
Derivative assets not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	MTM derivative assets	$	8	$	(b)	$	(b)
	Other current assets		—		8		—
	Other assets		4		4		—
Natural gas	MTM derivative assets		1		(b)		(b)
	Other current assets		—		—		1
	Other assets		1		1		—
Power	MTM derivative assets		14		(b)		(b)
	Other current assets		—		14		—
	Other assets		1		1		—
	Total assets	$	29	$	28	$	1
Derivative liabilities not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	MTM derivative liabilities	$	2	$	(b)	$	—
	Other current liabilities		—		2		—
	Other deferred credits and liabilities		2		2		—
Natural gas	MTM derivative liabilities		64		(b)		56
	Other current liabilities		—		8		—
	Other deferred credits and liabilities		45		7		38
Power	MTM derivative liabilities		25		(b)		21
	Other current liabilities		—		4		—
	Other deferred credits and liabilities		90		—		90
Uranium	MTM derivative liabilities		1		(b)		—
	Other current liabilities		—		1		—
	Other deferred credits and liabilities		1		1		—
	Total liabilities	$	230	$	25	$	205

(a) Includes derivatives subject to regulatory deferral.

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

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in regulatory assets or regulatory liabilities as of March 31, 2013, and December 31, 2012:

	Ameren			Ameren Missouri			Ameren Illinois
2013
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Fuel oils derivative contracts(a)	$	4		$	4		$	—
Natural gas derivative contracts(b)	(71		)	(10		)	(61		)
Power derivative contracts(c)	(79		)	2			(81		)
Uranium derivative contracts(d)	(2		)	(2		)	—
2012
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Fuel oils derivative contracts(a)	$	4		$	4		$	—
Natural gas derivative contracts(b)	(107		)	(14		)	(93		)
Power derivative contracts(c)	(99		)	12			(111		)
Uranium derivative contracts(d)	(2		)	(2		)	—

(a) 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 March 31, 2013. Current gains deferred as regulatory liabilities include $4 million and $4 million at Ameren and Ameren Missouri as of March 31, 2013, respectively. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of March 31, 2013, respectively.

(b) 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 March 31, 2013. Current gains deferred as regulatory liabilities include $6 million, $1 million, and $5 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2013. Current losses deferred as regulatory assets include $45 million, $7 million, and $38 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2013.

(c) Represents net gains (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 March 31, 2013. Current gains deferred as regulatory liabilities include $12 million and $12 million at Ameren and Ameren Missouri, respectively, as of March 31, 2013. Current losses deferred as regulatory assets include $21 million, $10 million, and $11 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2013.

(d) 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 March 31, 2013. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri as of March 31, 2013, respectively.

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

We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) 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.

Although Ameren had not previously elected to offset fair value amounts and collateral for derivative instruments executed with the same counterparty under the same master netting arrangement, authoritative accounting guidance, effective in the first quarter 2013, requires those amounts eligible to be offset to be presented both at the gross and net amounts. The following table provides the recognized gross derivative balances and the net amounts of those derivatives subject to an enforceable master netting arrangement or similar agreement as of March 31, 2013, and December 31, 2012:

			Gross Amounts Not Offset in the Balance Sheet
	Gross Amounts Recognized in the Balance Sheet		Derivative Instruments		Cash Collateral Received/Posted(a)		Net Amount
2013
Commodity contracts eligible to be offset:
Assets:
Ameren	$	37	$	20	$	—	$	17
Ameren Missouri	28		15		—		13
Ameren Illinois	9		5		—		4
Liabilities:
Ameren	$	183	$	20	$	39	$	124
Ameren Missouri	32		15		8		9
Ameren Illinois	151		5		31		115
2012
Commodity contracts eligible to be offset:
Assets:
Ameren	$	29	$	10	$	—	$	19
Ameren Missouri	28		9		—		19
Ameren Illinois	1		1		$	—	—
Liabilities:
Ameren	$	230	$	10	$	65	$	155
Ameren Missouri	25		9		7		9
Ameren Illinois	205		1		58		146

(a) Cash collateral received reduces gross asset balances and cash collateral posted reduces gross liability balances.

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 groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of March 31, 2013, and December 31, 2012, if counterparty groups were to fail completely 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		Commodity Marketing Companies		Electric Utilities		Financial Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Total
2013
Ameren Missouri	$	1	$	1	$	1	$	10	$	3	$	—	$	16
Ameren Illinois	—		2		—		4		—		2		8
Ameren	$	1	$	3	$	1	$	14	$	3	$	2	$	24
2012
Ameren Missouri	$	—	$	2	$	3	$	14	$	3	$	—	$	22
Ameren Illinois	—		—		—		1		—		—		1
Ameren	$	—	$	2	$	3	$	15	$	3	$	—	$	23

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 Ameren Companies held no cash from counterparties based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements at March 31, 2013 and December 31, 2012. As of March 31, 2013, other collateral used to reduce exposure consisted of letters of credit of less than $1 million held by Ameren and Ameren Missouri. As of December 31, 2012, other collateral used to reduce exposure consisted of letters of credit of $1 million held by Ameren and Ameren Missouri.

The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of March 31, 2013, and December 31, 2012:

	Affiliates		Commodity Marketing Companies		Electric Utilities		Financial Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Total
2013
Ameren Missouri	$	1	$	1	$	1	$	6	$	3	$	—	$	12
Ameren Illinois	—		2		—		2		—		—		4
Ameren	$	1	$	3	$	1	$	8	$	3	$	—	$	16
2012
Ameren Missouri	$	—	$	1	$	1	$	10	$	3	$	—	$	15
Ameren Illinois	—		—		—		—		—		—		—
Ameren	$	—	$	1	$	1	$	10	$	3	$	—	$	15

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of March 31, 2013, and December 31, 2012, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on March 31, 2013, or December 31, 2012, 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)
2013
Ameren Missouri	$	66	$	1	$	62
Ameren Illinois	121		31		78
Ameren	$	187	$	32	$	140
2012
Ameren Missouri	$	78	$	3	$	71
Ameren Illinois	148		58		84
Ameren	$	226	$	61	$	155

(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 determined after consideration of the effects of such agreements.

Derivatives that Qualify for Regulatory Deferral

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three months ended March 31, 2013, and 2012:

		Gain (Loss) Recognized in Regulatory  Liabilities or Regulatory Assets
		2013			2012
Ameren	Fuel oils	$	—		$	5
	Natural gas	36			(18		)
	Power(a)	20			(162		)
	Total	$	56		$	(175	)
Ameren Missouri	Fuel oils	$	—		$	5
	Natural gas	4			(2		)
	Power	(10		)	(1		)
	Total	$	(6	)	$	2
Ameren Illinois	Natural gas	$	32		$	(16	)
	Power	30			(144		)
	Total	$	62		$	(160	)

(a) Amounts include intercompany eliminations.

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Related Party Transactions

3 Months Ended

Mar. 31, 2013

Text Block [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

Ameren and its subsidiaries 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 which gave Genco the option to sell to AERG all, but not less than all, of the Elgin, Gibson City, and Grand Tower gas-fired energy centers. The put option agreement required AERG to secure and maintain an Ameren guarantee of payment of contingent obligations under the agreement. Ameren provided such a guarantee on March 28, 2012.

On March 14, 2013, the put option agreement was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley. The guarantee provided by Ameren was also modified to replace references to AERG with references to Medina Valley. The guarantee will remain in effect until either Medina Valley or Ameren satisfies all of the payment obligations under the put option agreement, or until the put option agreement is terminated and no further payments are owed by Medina Valley to Genco. On March 14, 2013, Genco exercised the option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

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, 2012, and March 31, 2013, 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, beginning in June 2012, 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. Marketing Company sells and Ameren Illinois purchases 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 March 31, 2013, Ameren Illinois’ payable to Marketing Company for the purchase of trade receivables totaled $9 million. During the three months ended March 31, 2013, Ameren Illinois purchased $33 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 Ameren’s consolidated financial statements. After the New AER divestiture is complete, these transactions will no longer be eliminated in Ameren’s consolidated financial statements.

Parent Company Guarantees

In the ordinary course of business, Ameren (parent) enters into various agreements providing financial assurance to third parties on behalf of its subsidiaries. Such agreements include, for example, guarantees and letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit and reducing the amount of cash collateral required to be posted. These agreements guarantee performance by Ameren's subsidiaries of obligations already existing on Ameren's consolidated balance sheet.

Upon the divestiture of New AER, subject to certain exceptions, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture and provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. IPH shall indemnify Ameren for any payments it makes pursuant to these credit support obligations. IPH's indemnification obligation will be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH's indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions). See Note 2 - Divestiture Transactions and Discontinued Operations.

At March 31, 2013, Ameren had a total of $269 million in guarantees outstanding, which included:

• $158 million related to Ameren's Merchant Generation segment, primarily for Marketing Company as support for physically and financially settled power transactions with its counterparties. As of March 31, 2013, this amount does not represent an incremental consolidated Ameren obligation; rather, it represents Ameren parental guarantees of subsidiary obligations to third parties, which may include affiliates, in order to allow the subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Ameren's estimated exposure for obligations under transactions covered by these guarantees was $26 million at March 31, 2013, which represents the total amount Ameren (parent) could be required to fund based on March 31, 2013, market prices.

• $33 million associated with the guarantee provided by Ameren for Medina Valley on March 14, 2013, relating to the amended put option agreement between Genco and Medina Valley. Genco exercised the put option in March 2013 and received an initial payment of $100 million. Genco advanced the initial payment amount it received into the non-state-regulated subsidiaries money pool.

• $65 million provided to two clearing brokers acting as futures commission merchants for the clearing of certain power, natural gas, and fuels commodity transactions for AER. As of March 31, 2013, AER was transitioning from its existing futures commission merchant to a new futures commission merchant. As of May 1, 2013, following completion of this transition, only one guarantee for $25 million is required.

• $13 million related to requirements for asset transactions, leasing, and other service agreements. At March 31, 2013, Ameren estimated it had no exposure to any of these guarantees.

Additionally, at March 31, 2013, Ameren had issued letters of credit totaling $37 million as credit support to certain subsidiaries.

Money Pools

See Note 4 - Short-term Debt and Liquidity for a discussion of affiliate borrowing arrangements.

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three months ended March 31, 2013, and 2012. 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 4 - Short-term Debt and Liquidity of this report.

			Three Months ended March 31
Agreement	Income Statement Line Item		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2013	$	1	$ (a)
agreements with Ameren Illinois		2012	(b)		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2013	5		(b)
rent and facility services		2012	5		(b)
Ameren Missouri and Genco gas	Operating Revenues	2013	(b)		(a)
transportation agreement		2012	(b)		(a)
Transmission services agreement	Operating Revenues	2013	(a)		6
with Marketing Company		2012	(a)		2
Total Operating Revenues		2013	$	6	$	6
		2012	5		2
Ameren Illinois power supply	Purchased Power	2013	$ (a)		$	26
agreements with Marketing Company		2012	(a)		87
Ameren Illinois power supply	Purchased Power	2013	(a)		1
agreements with Ameren Missouri		2012	(a)		(b)
Total Purchased Power		2013	$ (a)		$	27
		2012	(a)		87
Ameren Services support services	Other Operations and Maintenance	2013	$	31	$	25
agreement		2012	28		23
Insurance premiums(c)	Other Operations and Maintenance	2013	(b)		(a)
		2012	(b)		(a)
Total Other Operations and		2013	$	31	$	25
Maintenance Expenses		2012	28		23
Money pool borrowings (advances)	Interest Charges	2013	$ (b)		$ (b)
		2012	—		(b)

(a) Not applicable.

(b) Amount less than $1 million.

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

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Related Party Transactions (Schedule of Related Party Transactions) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Union Electric Company [Member]
Related Party Transaction [Line Items]
Operating Revenues	$ 6		$ 5
Operating Expenses	31		28
Ameren Illinois Company [Member]
Related Party Transaction [Line Items]
Operating Revenues	6		2
Operating Expenses	25		23
Ameren Missouri Power Supply Agreements with Ameren Illinois [Member] | Union Electric Company [Member]
Related Party Transaction [Line Items]
Operating Revenues	1		1	[1]
Ameren Missouri and Ameren Illinois Rent and Facility Services [Member] | Union Electric Company [Member]
Related Party Transaction [Line Items]
Operating Revenues	5		5
Ameren Missouri and Ameren Illinois Rent and Facility Services [Member] | Ameren Illinois Company [Member]
Related Party Transaction [Line Items]
Operating Revenues	1	[1]	1	[1]
Ameren Missouri and Genco Gas Transportation Agreement [Member] | Union Electric Company [Member]
Related Party Transaction [Line Items]
Operating Revenues	1	[1]	1	[1]
Ameren Illinois Transmission Services Agreement with Marketing Company [Member] | Ameren Illinois Company [Member]
Related Party Transaction [Line Items]
Operating Revenues	6		2
Ameren Illinois Power Supply Agreements with Marketing Company [Member] | Ameren Illinois Company [Member]
Related Party Transaction [Line Items]
Operating Expenses	26		87
Purchased Power [Member] | Ameren Illinois Company [Member]
Related Party Transaction [Line Items]
Operating Expenses	27		87
Ameren Services Support Services Agreement [Member] | Union Electric Company [Member]
Related Party Transaction [Line Items]
Operating Expenses	31		28
Ameren Services Support Services Agreement [Member] | Ameren Illinois Company [Member]
Related Party Transaction [Line Items]
Operating Expenses	25		23
Ameren Illinois Power Supply Agreements with Ameren Missouri [Member] | Union Electric Company [Member]
Related Party Transaction [Line Items]
Interest Charges	1	[1]	0
Ameren Illinois Power Supply Agreements with Ameren Missouri [Member] | Ameren Illinois Company [Member]
Related Party Transaction [Line Items]
Interest Charges	1	[1]	1	[1]
Operating Expenses	1		1	[1]
Insurance Premiums [Member] | Union Electric Company [Member]
Related Party Transaction [Line Items]
Operating Expenses	$ 1	[1],[2]	$ 1	[1],[2]

[1] Amount less than $1 million.

[2] Represents insurance premiums paid to Missouri Energy Risk Assurance Company, an affiliate for replacement power, property damage and terrorism coverage.

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Commitments And Contingencies (Other Obligations) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013
Commitments And Contingencies [Line Items]
Unrecorded Unconditional Purchase Obligation	$ 7,515
Unrecognized tax benefits	190
Union Electric Company [Member]
Commitments And Contingencies [Line Items]
Unrecorded Unconditional Purchase Obligation	5,151
Unrecognized tax benefits	126
Ameren Illinois Company [Member]
Commitments And Contingencies [Line Items]
Unrecorded Unconditional Purchase Obligation	2,316
Unrecognized tax benefits	$ 4

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Related Party Transactions (Narrative) (Detail) (USD $) In Millions, unless otherwise specified					3 Months Ended			0 Months Ended
	Mar. 31, 2013 people	Mar. 31, 2013 Medina Valley Energy Center [Member]	Mar. 31, 2013 Futures Commission Merchants [Member]	Mar. 31, 2013 Ameren Energy Marketing Company [Member]	Mar. 31, 2013 Ameren Energy Marketing Company [Member] Ameren Illinois Company [Member]	Mar. 31, 2013 Guarantee Type, Other [Member]	Apr. 30, 2013 Subsequent Event [Member] Futures Commission Merchants [Member]	Mar. 14, 2013 Elgin, Gibson City and Grand Tower Energy Centers [Member] Ameren Energy Generating Company [Member]	Mar. 14, 2013 New Ameren Energy Resources Company, LLC [Member]
Related Party Transaction [Line Items]
Proceeds from sale of property, plant, and equipment								$ 100
Accounts payable, related parties					9
Purchase of receivables from Marketing Company					33
Related Party Transaction, Purchases of Financing Receivable, Discount					1
Related Party Transaction, Guarantees Outstanding	269	33	65	158		13	25
Related Party Transaction, Guarantees, Number of Clearing Brokers	2
Related Party Transaction, Guarantees, Maximum Exposure				26
Letters of Credit Outstanding, Amount	37
Obligation to provide credit support, period									24 months
Buyer's indemnification guarantee obligation									$ 25
Buyer's indemnification guarantee obligation, period									24 months

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Summary Of Significant Accounting Policies (Schedule Of Amortization Expense Based On Usage Of Renewable Energy Credits And Emission Allowances) (Detail) (REC and Emission Allowances [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	$ 4		$ 1	[1]
Union Electric Company [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	1	[1]	1	[1]
Ameren Illinois Company [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	$ 4		$ 1	[1]

[1] Less than $1 million.

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Derivative Financial Instruments (Offsetting Derivative Assets and Liabilities) (Details) (Commodity Contract [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Offsetting Assets and Liabilities [Line Items]
Gross Amounts Recognized in the Balance Sheet	$ 37	[1]	$ 29	[1]
Derivative Instruments	20		10
Cash Collateral Received/Posted		[2]		[2]
Net Amount	17		19
Gross Amounts Recognized in the Balance Sheet	183	[1]	230	[1]
Derivative Instruments	20		10
Cash Collateral Received/Posted	39	[2]	65	[2]
Net Amount	124		155
Union Electric Company [Member]
Offsetting Assets and Liabilities [Line Items]
Gross Amounts Recognized in the Balance Sheet	28	[1]	28	[1]
Derivative Instruments	15		9
Cash Collateral Received/Posted		[2]		[2]
Net Amount	13		19
Gross Amounts Recognized in the Balance Sheet	32	[1]	25	[1]
Derivative Instruments	15		9
Cash Collateral Received/Posted	8	[2]	7	[2]
Net Amount	9		9
Ameren Illinois Company [Member]
Offsetting Assets and Liabilities [Line Items]
Gross Amounts Recognized in the Balance Sheet	9		1
Derivative Instruments	5		1
Cash Collateral Received/Posted		[2]		[2]
Net Amount	4
Gross Amounts Recognized in the Balance Sheet	151	[1]	205	[1]
Derivative Instruments	5		1
Cash Collateral Received/Posted	31	[2]	58	[2]
Net Amount	$ 115		$ 146

[1] The derivative asset and liability balances are presented net of counterparty credit considerations.

[2] Cash collateral received reduces gross asset balances and cash collateral posted reduces gross liability balances.

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Summary Of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Consolidation

The financial statements of Ameren 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 ended March 31, 2013, and 2012. The number of dilutive restricted stock shares and performance share units had an immaterial impact on earnings per share.

Intangible Assets

Ameren and Ameren Missouri classify emission allowances and renewable energy credits as intangible assets. Ameren Illinois consumes renewable energy credits as they are purchased through the IPA procurement process and expenses them immediately. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

At March 31, 2013, 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 Ameren’s and Ameren Missouri’s renewable energy credits was $16 million and $16 million, respectively, at March 31, 2013. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $14 million and $14 million, respectively, at December 31, 2012.

Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations.

Excise Taxes

Excise taxes levied on us are reflected on Ameren Missouri electric customer bills and on 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.

Uncertain Tax Positions

The amount of unrecognized tax benefits as of March 31, 2013, was $190 million, $126 million, and $4 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The amount of unrecognized tax benefits (detriments) as of March 31, 2013, that would impact the effective tax rate, if recognized, was $48 million, $1 million, and $(1) million for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The Ameren amount increased by $47 million in the first three months of 2013. This increase was primarily due to uncertainty related to the historical computation of Ameren’s tax basis in its stock investment in AER.

Ameren’s federal income tax returns for the years 2007 through 2010 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2011 is currently under examination.

It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the next 12 months for the years 2007 through 2010. This settlement, primarily related to uncertain tax positions for capitalization versus currently deductible repair expense and research tax deductions, is expected to result in a decrease in uncertain tax benefits of approximately $126 million, $110 million, and $5 million for Ameren, Ameren Missouri and Ameren Illinois, respectively. In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe any such increases or decreases, including the decrease from the reasonably possible IRS Appeals Office settlement discussed above, would be material to their results of operations, financial position, or liquidity.

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.

Asset Retirement Obligations

Based on the transaction agreement to divest New AER to IPH, Ameren will retain the AROs associated with the Meredosia and Hutsonville energy centers. Therefore, these AROs are classified as continuing operations. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

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.

Accounting and Reporting Developments

The following is a summary of recently adopted authoritative accounting guidance that could impact the Ameren Companies.

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect the Ameren Companies’ results of operations, financial position, or liquidity.

In February 2013, FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. This guidance was effective for the Ameren Companies beginning in the first quarter of 2013. The implementation of this amendment did not affect the Ameren Companies’ results of operations, financial position, or liquidity. The only amounts reclassified out of accumulated OCI for the Ameren Companies related to pension and other postretirement plan activity. These amounts were immaterial during the first quarter of 2013 and 2012, and therefore no additional disclosures required.

Disclosures about Offsetting Assets and Liabilities

In December 2011, FASB issued additional authoritative guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The amendments did not affect the Ameren Companies’ results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. The Ameren Companies adopted this guidance for the first quarter of 2013. See Note 7 - Derivative Financial Instruments for the required additional disclosures.

Derivatives

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.

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 March 31, 2013, its estimated investment performance through March 31, 2013, and its pension funding policy, Ameren expects to make annual contributions of $60 million to $150 million in each of the next five years, with aggregate estimated contributions of $550 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’s beneficiary association (VEBA) trusts to match the annual postretirement expense.

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Derivative Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Open Gross Derivative Volumes By Commodity Type

The following table presents open gross commodity contract volumes by commodity type as of March 31, 2013, and December 31, 2012:

	Quantity (in millions, except as indicated)
Commodity	Accrual & NPNS Contracts(a)		Other Derivatives(b)		Derivatives That Qualify for Regulatory Deferral(c)
	2013	2012	2013	2012	2013	2012
Coal (in tons)
Ameren Missouri & Ameren	91	96	(d)	(d)	(d)	(d)
Fuel oils (in gallons)(e)
Ameren Missouri & Ameren	(d)	(d)	(d)	(d)	67	26
Natural gas (in mmbtu)
Ameren Missouri	3	4	1	—	21	19
Ameren Illinois	12	16	(d)	(d)	137	128
Ameren	15	20	1	—	158	147
Power (in megawatthours)
Ameren Missouri	4	3	2	2	8	9
Ameren Illinois	19	21	(d)	(d)	12	14
Ameren	23	24	2	2	20	23
Renewable energy credits(f)
Ameren Missouri	3	3	(d)	(d)	(d)	(d)
Ameren Illinois	12	12	(d)	(d)	(d)	(d)
Ameren	15	15	(d)	(d)	(d)	(d)
Uranium (pounds in thousands)
Ameren Missouri & Ameren	4,950	5,142	(d)	(d)	480	446

(a) Accrual contracts include commodity contracts that do not qualify as derivatives. As of March 31, 2013, these contracts ran through December 2017, March 2015, September 2024, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively.

(b) As of March 31, 2013, these contracts ran through April 2013 and December 2014 for natural gas and power, respectively.

(c) As of March 31, 2013, these contracts ran through October 2015, March 2017, May 2032, and September 2014 for fuel oils, natural gas, power, and uranium, respectively.

(d) Not applicable.

(e) Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.

(f) A renewable energy credit is created for every one megawatthour of renewable energy generated. The Ameren Companies’ contracts include renewable energy credits from solar and wind-generated power.

Derivative Instruments Carrying Value

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 rec

Cumulative Pretax Net Gains (Losses) On All Derivative Instruments In OCI

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in regulatory assets or regulatory liabilities as of March 31, 2013, and December 31, 2012:

	Ameren			Ameren Missouri			Ameren Illinois
2013
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Fuel oils derivative contracts(a)	$	4		$	4		$	—
Natural gas derivative contracts(b)	(71		)	(10		)	(61		)
Power derivative contracts(c)	(79		)	2			(81		)
Uranium derivative contracts(d)	(2		)	(2		)	—
2012
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Fuel oils derivative contracts(a)	$	4		$	4		$	—
Natural gas derivative contracts(b)	(107		)	(14		)	(93		)
Power derivative contracts(c)	(99		)	12			(111		)
Uranium derivative contracts(d)	(2		)	(2		)	—

(a) 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 March 31, 2013. Current gains deferred as regulatory liabilities include $4 million and $4 million at Ameren and Ameren Missouri as of March 31, 2013, respectively. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of March 31, 2013, respectively.

(b) 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 March 31, 2013. Current gains deferred as regulatory liabilities include $6 million, $1 million, and $5 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2013. Current losses deferred as regulatory assets include $45 million, $7 million, and $38 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2013.

(c) Represents net gains (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 March 31, 2013. Current gains deferred as regulatory liabilities include $12 million and $12 million at Ameren and Ameren Missouri, respectively, as of March 31, 2013. Current losses deferred as regulatory assets include $21 million, $10 million, and $11 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2013.

(d) 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 March 31, 2013. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri as of March 31, 2013, respectively.

Offsetting Derivative Assets and Liabilities

The following table provides the recognized gross derivative balances and the net amounts of those derivatives subject to an enforceable master netting arrangement or similar agreement as of March 31, 2013, and December 31, 2012:

			Gross Amounts Not Offset in the Balance Sheet
	Gross Amounts Recognized in the Balance Sheet		Derivative Instruments		Cash Collateral Received/Posted(a)		Net Amount
2013
Commodity contracts eligible to be offset:
Assets:
Ameren	$	37	$	20	$	—	$	17
Ameren Missouri	28		15		—		13
Ameren Illinois	9		5		—		4
Liabilities:
Ameren	$	183	$	20	$	39	$	124
Ameren Missouri	32		15		8		9
Ameren Illinois	151		5		31		115
2012
Commodity contracts eligible to be offset:
Assets:
Ameren	$	29	$	10	$	—	$	19
Ameren Missouri	28		9		—		19
Ameren Illinois	1		1		$	—	—
Liabilities:
Ameren	$	230	$	10	$	65	$	155
Ameren Missouri	25		9		7		9
Ameren Illinois	205		1		58		146

(a) Cash collateral received reduces gross asset balances and cash collateral posted reduces gross liability balances.

Maximum Exposure If Counterparties Fail To Perform On Contracts

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		Commodity Marketing Companies		Electric Utilities		Financial Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Total
2013
Ameren Missouri	$	1	$	1	$	1	$	10	$	3	$	—	$	16
Ameren Illinois	—		2		—		4		—		2		8
Ameren	$	1	$	3	$	1	$	14	$	3	$	2	$	24
2012
Ameren Missouri	$	—	$	2	$	3	$	14	$	3	$	—	$	22
Ameren Illinois	—		—		—		1		—		—		1
Ameren	$	—	$	2	$	3	$	15	$	3	$	—	$	23

Potential Loss On Counterparty Exposures

The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of March 31, 2013, and December 31, 2012:

	Affiliates		Commodity Marketing Companies		Electric Utilities		Financial Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Total
2013
Ameren Missouri	$	1	$	1	$	1	$	6	$	3	$	—	$	12
Ameren Illinois	—		2		—		2		—		—		4
Ameren	$	1	$	3	$	1	$	8	$	3	$	—	$	16
2012
Ameren Missouri	$	—	$	1	$	1	$	10	$	3	$	—	$	15
Ameren Illinois	—		—		—		—		—		—		—
Ameren	$	—	$	1	$	1	$	10	$	3	$	—	$	15

Derivative Instruments With Credit Risk-Related Contingent Features

The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on March 31, 2013, or December 31, 2012, 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)
2013
Ameren Missouri	$	66	$	1	$	62
Ameren Illinois	121		31		78
Ameren	$	187	$	32	$	140
2012
Ameren Missouri	$	78	$	3	$	71
Ameren Illinois	148		58		84
Ameren	$	226	$	61	$	155

(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 determined after consideration of the effects of such agreements.

Derivatives That Qualify For Regulatory Deferral

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three months ended March 31, 2013, and 2012:

		Gain (Loss) Recognized in Regulatory  Liabilities or Regulatory Assets
		2013			2012
Ameren	Fuel oils	$	—		$	5
	Natural gas	36			(18		)
	Power(a)	20			(162		)
	Total	$	56		$	(175	)
Ameren Missouri	Fuel oils	$	—		$	5
	Natural gas	4			(2		)
	Power	(10		)	(1		)
	Total	$	(6	)	$	2
Ameren Illinois	Natural gas	$	32		$	(16	)
	Power	30			(144		)
	Total	$	62		$	(160	)

(a) Amounts include intercompany eliminations.

XML

Derivative Financial Instruments (Derivative Instruments Carrying Value) (Detail) (Not Designated As Hedging Instrument [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Derivative [Line Items]
Derivative assets	$ 37	[1]	$ 29	[1]
Derivative liabilities	183	[1]	230	[1]
Fuel Oils [Member] | Mark To Market Derivative Assets [Member]
Derivative [Line Items]
Derivative assets	6	[1]	8	[1]
Fuel Oils [Member] | Other Assets [Member]
Derivative [Line Items]
Derivative assets	4	[1]	4	[1]
Fuel Oils [Member] | Mark To Market Derivative Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	1	[1]	2	[1]
Fuel Oils [Member] | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	2	[1]	2	[1]
Natural Gas [Member] | Mark To Market Derivative Assets [Member]
Derivative [Line Items]
Derivative assets	6	[1]	1	[1]
Natural Gas [Member] | Other Assets [Member]
Derivative [Line Items]
Derivative assets	2	[1]	1	[1]
Natural Gas [Member] | Mark To Market Derivative Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	45	[1]	64	[1]
Natural Gas [Member] | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	34	[1]	45	[1]
Power [Member] | Mark To Market Derivative Assets [Member]
Derivative [Line Items]
Derivative assets	15	[1]	14	[1]
Power [Member] | Other Assets [Member]
Derivative [Line Items]
Derivative assets	4	[1]	1	[1]
Power [Member] | Mark To Market Derivative Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	25	[1]	25	[1]
Power [Member] | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	74	[1]	90	[1]
Uranium [Member] | Mark To Market Derivative Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	2	[1]	1	[1]
Uranium [Member] | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities			1	[1]
Union Electric Company [Member]
Derivative [Line Items]
Derivative assets	28	[1]	28	[1]
Derivative liabilities	32	[1]	25	[1]
Union Electric Company [Member] | Fuel Oils [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative assets	6	[1]	8	[1]
Union Electric Company [Member] | Fuel Oils [Member] | Other Assets [Member]
Derivative [Line Items]
Derivative assets	4	[1]	4	[1]
Union Electric Company [Member] | Fuel Oils [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	1	[1]	2	[1]
Union Electric Company [Member] | Fuel Oils [Member] | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	2	[1]	2	[1]
Union Electric Company [Member] | Natural Gas [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative assets	1	[1]
Union Electric Company [Member] | Natural Gas [Member] | Other Assets [Member]
Derivative [Line Items]
Derivative assets	1	[1]	1	[1]
Union Electric Company [Member] | Natural Gas [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	7	[1]	8	[1]
Union Electric Company [Member] | Natural Gas [Member] | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	5	[1]	7	[1]
Union Electric Company [Member] | Power [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative assets	15	[1]	14	[1]
Union Electric Company [Member] | Power [Member] | Other Assets [Member]
Derivative [Line Items]
Derivative assets	1	[1]	1	[1]
Union Electric Company [Member] | Power [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	14	[1]	4	[1]
Union Electric Company [Member] | Power [Member] | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	1	[1]
Union Electric Company [Member] | Uranium [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	2	[1]	1	[1]
Union Electric Company [Member] | Uranium [Member] | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities			1	[1]
Ameren Illinois Company [Member]
Derivative [Line Items]
Derivative assets	9	[1]	1	[1]
Derivative liabilities	151	[1]	205	[1]
Ameren Illinois Company [Member] | Natural Gas [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative assets	5	[1]	1	[1]
Ameren Illinois Company [Member] | Natural Gas [Member] | Other Assets [Member]
Derivative [Line Items]
Derivative assets	1	[1]
Ameren Illinois Company [Member] | Natural Gas [Member] | Mark To Market Derivative Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	38	[1]	56	[1]
Ameren Illinois Company [Member] | Natural Gas [Member] | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	29	[1]	38	[1]
Ameren Illinois Company [Member] | Power [Member] | Other Assets [Member]
Derivative [Line Items]
Derivative assets	3	[1]
Ameren Illinois Company [Member] | Power [Member] | Mark To Market Derivative Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	11	[1]	21	[1]
Ameren Illinois Company [Member] | Power [Member] | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	$ 73	[1]	$ 90	[1]

[1] Includes derivatives subject to regulatory deferral.

XML

Rate And Regulatory Matters (Narrative-Missouri) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended				1 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 Union Electric Company [Member]	Mar. 31, 2012 Union Electric Company [Member]	Apr. 30, 2011 Union Electric Company [Member] Fac Prudence Review [Member]	Jul. 31, 2011 Union Electric Company [Member] Accounting Authority Order Request [Member] Fac Prudence Review [Member]	Feb. 29, 2012 Subsequent Periods After September 30, 2009 [Member] Mopsc Staff Report [Member] Fac Prudence Review [Member]
Rate And Regulatory Matters [Line Items]
Contested amounts under the FAC					$ 18		$ 26
Interest Charges	101	98	60	56	1
Request to defer fixed costs not recovered from Noranda, amount						$ 36

XML

Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Current Assets:
Cash and cash equivalents	$ 161		$ 184
Accounts receivable - trade (less allowance for doubtful accounts)	479		354
Unbilled revenue	262		291
Miscellaneous accounts and notes receivable	70		71
Materials and supplies	461		570
Mark-to-market derivative assets	27		23
Current regulatory assets	196		247
Current accumulated deferred income taxes, net	80		160
Other current assets	60		75
Current assets of discontinued operations	1,500		1,600
Total current assets	3,296		3,575
Property and Plant, Net	15,408		15,348
Investments and Other Assets:
Nuclear decommissioning trust fund	437		408
Goodwill	411		411
Intangible assets	16		14
Regulatory assets	1,719		1,785
Other assets	665		668
Total investments and other assets	3,248		3,286
TOTAL ASSETS	21,952		22,209
Current Liabilities:
Current maturities of long-term debt	355		355
Accounts and wages payable	341		533
Taxes accrued	91		50
Interest accrued	111		89
Customer deposits	110		107
Mark-to-market derivative liabilities	73		92
Current regulatory liabilities	135		100
Other current liabilities	163		168
Current liabilities of discontinued operations	1,198		1,166
Total current liabilities	2,577		2,660
Long-term Debt, Net	5,803		5,802
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	3,235		3,166
Accumulated deferred investment tax credits	68		70
Regulatory liabilities	1,667		1,589
Asset retirement obligations	380		375
Pension and other postretirement benefits	1,113		1,138
Other deferred credits and liabilities	593		642
Total deferred credits and other liabilities	7,056		6,980
Commitments and Contingencies
Stockholders' Equity:
Common Stock	2		2
Other paid-in capital	5,614		5,616
Retained earnings	764		1,006
Accumulated other comprehensive gain (loss)	(15)		(8)
Stockholder's equity	6,365		6,616
Noncontrolling Interest	151	[1]	151	[1]
Total equity	6,516		6,767
TOTAL LIABILITIES AND EQUITY	21,952		22,209
Union Electric Company [Member]
Current Assets:
Cash and cash equivalents	1		148
Advances to money pool			24
Accounts receivable - trade (less allowance for doubtful accounts)	202		161
Accounts receivable - affiliates	6		4
Unbilled revenue	151		145
Miscellaneous accounts and notes receivable	49		48
Materials and supplies	375		397
Current regulatory assets	144		163
Other current assets	51		69
Total current assets	979		1,159
Property and Plant, Net	10,152		10,161
Investments and Other Assets:
Nuclear decommissioning trust fund	437		408
Intangible assets	16		14
Regulatory assets	832		852
Other assets	451		449
Total investments and other assets	1,736		1,723
TOTAL ASSETS	12,867		13,043
Current Liabilities:
Current maturities of long-term debt	205		205
Borrowings from money pool	5
Accounts and wages payable	153		345
Accounts payable - affiliates	65		66
Taxes accrued	66		28
Interest accrued	53		60
Current regulatory liabilities	23		18
Other current liabilities	86		77
Total current liabilities	656		799
Long-term Debt, Net	3,801		3,801
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	2,426		2,443
Accumulated deferred investment tax credits	63		64
Regulatory liabilities	968		917
Asset retirement obligations	351		346
Pension and other postretirement benefits	452		461
Other deferred credits and liabilities	146		158
Total deferred credits and other liabilities	4,406		4,389
Commitments and Contingencies
Stockholders' Equity:
Common Stock	511		511
Other paid-in capital	1,556		1,556
Preferred stock not subject to mandatory redemption	80		80
Retained earnings	1,857		1,907
Stockholder's equity	4,004		4,054
TOTAL LIABILITIES AND EQUITY	12,867		13,043
Ameren Illinois Company [Member]
Current Assets:
Cash and cash equivalents	93		0
Advances to money pool	5
Accounts receivable - trade (less allowance for doubtful accounts)	274		182
Accounts receivable - affiliates	13		10
Unbilled revenue	111		146
Miscellaneous accounts and notes receivable	21		22
Materials and supplies	86		173
Current regulatory assets	52		84
Current accumulated deferred income taxes, net	56		85
Other current assets	36		47
Total current assets	747		749
Property and Plant, Net	5,117		5,052
Investments and Other Assets:
Tax receivable - Genco	38		39
Goodwill	411		411
Regulatory assets	887		934
Other assets	88		97
Total investments and other assets	1,424		1,481
TOTAL ASSETS	7,288		7,282
Current Liabilities:
Current maturities of long-term debt	150		150
Borrowings from money pool			24
Accounts and wages payable	151		146
Accounts payable - affiliates	74		86
Taxes accrued	21		18
Interest accrued	41		22
Customer deposits	86		85
Mark-to-market derivative liabilities	49		77
Environmental remediation	44		37
Current regulatory liabilities	113		82
Other current liabilities	63		70
Total current liabilities	792		797
Long-term Debt, Net	1,577		1,577
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,046		1,025
Accumulated deferred investment tax credits	5		5
Regulatory liabilities	699		672
Pension and other postretirement benefits	396		406
Accrued Environmental Loss Contingencies, Noncurrent	211		216
Other deferred credits and liabilities	146		183
Total deferred credits and other liabilities	2,503		2,507
Commitments and Contingencies
Stockholders' Equity:
Common Stock
Other paid-in capital	1,965		1,965
Preferred stock not subject to mandatory redemption	62		62
Retained earnings	376		360
Accumulated other comprehensive gain (loss)	13		14
Stockholder's equity	2,416		2,401
TOTAL LIABILITIES AND EQUITY	$ 7,288		$ 7,282

[1] Includes the 20% EEI ownership interest not owned by Ameren. The assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Current assets of discontinued operations” and “Current liabilities of discontinued operations,” however, the 20% ownership interest not owned by Ameren was included in “Noncontrolling interests” on Ameren’s March 31, 2013, and December 31, 2012 balance sheet. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.

XML

Rate And Regulatory Matters

3 Months Ended

Mar. 31, 2013

Public Utilities, General Disclosures [Abstract]

RATE AND REGULATORY MATTERS

RATE AND REGULATORY MATTERS

Below is a summary of updates to 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

FAC Prudence Reviews

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.

Ameren Missouri disagrees with the MoPSC order's classification of these sales and believed 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 and a group of large industrial customers 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. A decision is expected to be issued in 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. 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 amount covered by the accounting authority order, if it is granted.

The MoPSC’s FAC prudence review for the period from June 1, 2011, to September 30, 2012, was initiated on March 1, 2013. The MoPSC is expected to issue an order for this prudence review in 2013.

Illinois

IEIMA

In September 2012, the ICC issued an order in Ameren Illinois’ initial filing under the IEIMA’s performance-based formula rate framework. In October 2012, Ameren Illinois filed an appeal of the ICC’s initial filing order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013. Ameren Illinois believes the ICC incorrectly implemented the IEIMA by using an average capital structure as opposed to a year-end capital structure on the revenue requirement, the method it used for calculating the equity portion of Ameren Illinois' capital structure, the method for calculating interest and the average rate base rather than year-end rate base for the revenue requirement reconciliation.

In April 2012, Ameren Illinois submitted to the ICC an update filing under IEIMA. In December 2012, the ICC issued an order approving an Ameren Illinois electric delivery service revenue requirement of $765 million, based on 2011 recoverable costs and expected net plant additions for 2012. The delivery service rates became effective on January 1, 2013, and will be effective through the end of 2013. In January 2013, Ameren Illinois filed an appeal of the ICC's update filing order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013.

The ICC's orders in 2012 for Ameren Illinois’ initial and update rate filings jeopardize 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 slowing IEIMA capital spending with a corresponding negative effect on the job creation that the legislature sought to effectuate with the law. Ameren Illinois still intends to meet its IEIMA capital spending requirements.

On April 19, 2013, Ameren Illinois filed its annual electric delivery formula rate update with the ICC based on 2012 recoverable costs and expected net plant additions for 2013. Pending ICC approval, the update filing will result in a $30 million decrease in Ameren Illinois’ electric delivery revenue requirement beginning in January 2014. The filing includes a refund to customers of the 2012 revenue requirement reconciliation of approximately $50 million. An expected refund was recorded in 2012 as a regulatory liability on Ameren Illinois’ balance sheet. In the filing, the proposed refund is partially offset by an annual revenue requirement increase of approximately $20 million primarily due to increased recoverable costs over 2011 levels. The filing is based on an electric delivery service revenue requirement of $785 million, before consideration of the 2012 revenue requirement reconciliation refund. An ICC decision with respect to the April 2013 update filing is expected in December 2013 and will establish rates for 2014.

On March 14, 2013, the Illinois General Assembly passed legislation, which, if enacted, would result in certain amendments to the IEIMA that would modify its implementation. The passed legislation, Senate Bill 9, clarifies the provisions in the IEIMA that require the year-end rate base be used to calculate the revenue requirement reconciliation and that the interest applied to the revenue requirement reconciliation and return on equity collar adjustments would be consistent with the company’s weighted-average return calculated under the formula rate. Additionally, the legislation specifies the use of year-end capital structure for both the revenue requirement and the revenue requirement reconciliation. On May 5, 2013, the Illinois Governor vetoed this legislation. If this legislation is ultimately enacted through a legislative override in 2013, Ameren Illinois will submit revisions to its April 19, 2013 update filing based on the new law.

Federal

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. 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. In November 2012, a FERC administrative law judge issued an initial decision, which is now pending before FERC. The timing of a FERC decision is uncertain. Based on the administrative law judge's initial decision, Ameren and Ameren Illinois each has included on its balance sheet in “Current regulatory liabilities” as of March 31, 2013, an estimate of $9 million for the refund due to wholesale customers relating to billings from March 2011 through March 2013.

Ameren Illinois Electric Transmission Rate Refund

In July 2012, FERC issued an order with respect to 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 transmission formula rate, thereby inappropriately recovering a higher return on rate base from its electric transmission 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. After reviewing the FERC order and its calculation of the impact on electric transmission formula rates, Ameren Illinois concluded that no refund was warranted. Several wholesale customers filed a protest with FERC regarding Ameren's conclusion that no refund is 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 and the amount could be estimated.

Combined Construction and Operating License

In 2008, Ameren Missouri filed an application with the NRC for a COL for a new nuclear unit at Ameren Missouri's existing Callaway County, Missouri, 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 investment funds for the design, engineering, manufacturing, and sale of American-made small modular nuclear reactors. In April 2012, Ameren Missouri entered into an agreement with Westinghouse to exclusively support Westinghouse's application for the DOE's small modular nuclear 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. In November 2012, the DOE awarded investment funds for only one small modular reactor design, which was not the Westinghouse design, but also stated that additional investment funds would be awarded during 2013. Westinghouse continues to pursue investment funds from the DOE.

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 energy center 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 March 31, 2013, the DOE investment funds that would help support the COL application, and Ameren Missouri's 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. 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 is made.

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Fair Value Measurements (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Valuation adjustments related to net derivative contracts, liabilities	$ 1	$ 7
Union Electric Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Valuation adjustments related to net derivative contracts, liabilities	1	1
Ameren Illinois Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Valuation adjustments related to net derivative contracts, liabilities	$ 1	$ 7

XML

Commitments And Contingencies (Asbestos-Related Litigation And Tax Exemptions And Credits) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013 defendant lawsuit
Asbestos-Related [Member]
Loss Contingencies [Line Items]
Average number of total defendants named	80
Asbestos-related lawsuits were pending	103	[1]
Asbestos liabilities	$ 19.0
Percent of allowed cash expenditures in excess of base rates to be recovered through charges assessed to customers	90.00%
Asbestos trust fund balance	23
Percent of difference to be contributed to the asbestos trust fund if cash expenditures are less than amount included in base electric rates.	90.00%
Asbestos-Related [Member] | Union Electric Company [Member]
Loss Contingencies [Line Items]
Asbestos-related lawsuits were pending	66
Asbestos liabilities	8.0
Asbestos-Related [Member] | Ameren Illinois Company [Member]
Loss Contingencies [Line Items]
Asbestos-related lawsuits were pending	81
Asbestos liabilities	11.0
Asbestos-Related [Member] | Ameren Corporation [Member]
Loss Contingencies [Line Items]
Asbestos-related lawsuits were pending	3
Collectibility of Taxes [Member] | Ameren Illinois Company [Member]
Loss Contingencies [Line Items]
Asbestos liabilities	2.0
Public Utilities, Number of Customers	2,100
Loss contingency range of possible loss maximum	4.0
Claimed Manufacturing Exemptions And Credits [Member]
Loss Contingencies [Line Items]
Loss contingency range of possible loss maximum	$ 27.0

[1] Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Valuation Techniques [Table Text Block]

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 three months ended March 31, 2013:

		Fair Value								Weighted
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Average
Level 3 Derivative asset and liability - commodity contracts(a):
Ameren	Fuel oils	$	7	$	(2	)	Discounted cash flow	Escalation rate(%)(b)	.20 - .59	.39
								Counterparty credit risk(%)(c)(d)	.26 - 3	1
							Option model	Volatilities(%)(b)	10 - 19	17
	Natural gas	3		(1		)	Option model	Escalation rate(%)(b)	.20 - .46	.37
								Nodal basis($/mmbtu)(c)	(.24) - (.04)	(.19)
							Discounted cash flow	Escalation rate(%)(b)	.20 - .46	.35
								Nodal basis($/mmbtu)(c)	(.18) - 0	(.01)
								Counterparty credit risk(%)(c)(d)	.26 - 5	1
								Ameren credit risk(%)(c)(d)	2 - 3	3
	Power(e)	12		(91		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)	24 - 48	33
								Estimated auction price for FTRs($/MW)(b)	0 - 4,280	190
								Nodal basis($/MWh)(c)	(5) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	.22 - 5	2
								Ameren credit risk(%)(c)(d)	2 - 3	3
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	5 - 7	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)(d)	5 - 7	6
	Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	42 - 45	43
Ameren Missouri	Fuel oils	$	7	$	(2	)	Discounted cash flow	Escalation rate(%)(b)	.20 - .59	.39
								Counterparty credit risk(%)(c)(d)	.26 - 3	1
							Option model	Volatilities(%)(b)	10 - 19	17
	Natural gas	1		(1		)	Option model	Escalation rate(%)(b)	.20 - .46	.37
								Nodal basis($/mmbtu)(c)	(.24) - (.04)	(.19)
							Discounted cash flow	Escalation rate(%)(b)	.20 - .46	.26
								Nodal basis($/mmbtu)(c)	(.18) - (.02)	(.04)
								Counterparty credit risk(%)(c)(d)	.26 - 5	1
								Ameren Missouri credit risk(%)(c)(d)	2	(f)
	Power(e)	9		(7		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)	24 - 51	38
								Estimated auction price for FTRs($/MW)(b)	0 - 4,280	190
								Nodal basis($/MWh)(c)	(5) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	.22 - 5	1
								Ameren Missouri credit risk(%)(c)(d)	2	(f)
	Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	42 - 45	43
Ameren Illinois	Natural gas	$	2	$	—		Discounted cash flow	Escalation rate(%)(b)	.20 - .46	.33
								Nodal basis($/mmbtu)(c)	(.05) - 0	—
								Counterparty credit risk(%)(c)(d)	.70 - 2	1
								Ameren Illinois credit risk(%)(c)(d)	3	(f)
	Power(e)	3		(84		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(b)	24 - 42	32
								Nodal basis($/MWh)(b)	(4) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	2	(f)
								Ameren Illinois credit risk(%)(c)(d)	3	(f)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	5 - 7	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6

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

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

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

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

(e) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand.

(f) Not applicable.

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 twelve-month period ended December 31, 2012:

		Fair Value								Weighted
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Average
Level 3 Derivative asset and liability - commodity contracts(a):
Ameren	Fuel oils	$	8	$	(3	)	Discounted cash flow	Escalation rate(%)(b)	.21 - .60	.44
								Counterparty credit risk(%)(c)(d)	.12 - 1	1
								Ameren credit risk(%)(c)(d)	2	(e)
							Option model	Volatilities(%)(b)	7 - 27	24
	Power(f)	14		(114		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)	22 - 47	31
								Estimated auction price for FTRs($/MW)(b)	(281) - 1,851	178
								Nodal basis($/MWh)(c)	(5) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	.22 - 1	1
								Ameren credit risk(%)(c)(d)	2 - 5	5
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 8	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6
	Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	43 - 46	44
Ameren Missouri	Fuel oils	$	8	$	(3	)	Discounted cash flow	Escalation rate(%)(b)	.21 - .60	.44
								Counterparty credit risk(%)(c)(d)	.12 - 1	1
								Ameren Missouri credit risk(%)(c)(d)	2	(e)
							Option model	Volatilities(%)(b)	7 - 27	24
	Power(f)	14		(3		)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)	24 - 56	36
								Estimated auction price for FTRs($/MW)(b)	(281) - 1,851	178
								Nodal basis($/MWh)(c)	(5) - (1)	(2)
								Counterparty credit risk(%)(c)(d)	.22 - 1	1
								Ameren Missouri credit risk(%)(c)(d)	2
	Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	43 - 46	44
Ameren Illinois	Power(f)	$	—	$	(111	)	Discounted cash flow	Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(b)	22 - 47	30
								Nodal basis($/MWh)(b)	(5) - (1)	(3)
								Ameren Illinois credit risk(%)(c)(d)	5	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 8	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6

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

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

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

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

(e) Not applicable.

(f) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand.

Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of March 31, 2013:

		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	Derivative assets - commodity contracts(a):
	Fuel oils	$	3	$	—	$	7	$	10
	Natural gas	1		4		3		8
	Power	—		7		12		19
	Total derivative assets - commodity contracts	$	4	$	11	$	22	$	37
	Nuclear Decommissioning Trust Fund(b):
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	294		—		—		294
	Debt securities:
	Corporate bonds	—		48		—		48
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		77		—		77
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	296	$	138	$	—	$	434
	Total Ameren	$	300	$	149	$	22	$	471
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	3	$	—	$	7	$	10
	Natural gas	—		1		1		2
	Power	—		7		9		16
	Total derivative assets - commodity contracts	$	3	$	8	$	17	$	28
	Nuclear Decommissioning Trust Fund(b):
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	294		—		—		294
	Debt securities:
	Corporate bonds	—		48		—		48
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		77		—		77
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	296	$	138	$	—	$	434
	Total Ameren Missouri	$	299	$	146	$	17	$	462
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	1	$	3	$	2	$	6
	Power	—		—		3		3
	Total Ameren Illinois	$	1	$	3	$	5	$	9
Liabilities:
Ameren	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	1	$	—	$	2	$	3
	Natural gas	5		73		1		79
	Power	—		8		91		99
	Uranium	—		—		2		2
	Total Ameren	$	6	$	81	$	96	$	183
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	1	$	—	$	2	$	3
	Natural gas	5		6		1		12
	Power	—		8		7		15
	Uranium	—		—		2		2
	Total Ameren Missouri	$	6	$	14	$	12	$	32
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	67	$	—	$	67
	Power	—		—		84		84
	Total Ameren Illinois	$	—	$	67	$	84	$	151

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

(b) Balance excludes $3 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, 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	Derivative assets - commodity contracts(a):
	Fuel oils	$	4	$	—	$	8	$	12
	Natural gas	—		2		—		2
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	4	$	3	$	22	$	29
	Nuclear Decommissioning Trust Fund(b):
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	264		—		—		264
	Debt securities:
	Corporate bonds	—		47		—		47
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		81		—		81
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	265	$	141	$	—	$	406
	Total Ameren	$	269	$	144	$	22	$	435
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	4	$	—	$	8	$	12
	Natural gas	—		1		—		1
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	4	$	2	$	22	$	28
	Nuclear Decommissioning Trust Fund(b):
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	264		—		—		264
	Debt securities:
	Corporate bonds	—		47		—		47
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		81		—		81
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	265	$	141	$	—	$	406
	Total Ameren Missouri	$	269	$	143	$	22	$	434
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	—	$	1	$	—	$	1
	Power	—		—		—		—
	Total Ameren Illinois	$	—	$	1	$	—	$	1

		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	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	1	$	—	$	3	$	4
	Natural gas	7		102		—		109
	Power	—		1		114		115
	Uranium	—		—		2		2
	Total Ameren	$	8	$	103	$	119	$	230
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	1	$	—	$	3	$	4
	Natural gas	7		8		—		15
	Power	—		1		3		4
	Uranium	—		—		2		2
	Total Ameren Missouri	$	8	$	9	$	8	$	25
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	94	$	—	$	94
	Power	—		—		111		111
	Total Ameren Illinois	$	—	$	94	$	111	$	205

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

(b) Balance excludes $2 million of receivables, payables, and accrued income, net.

Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level Three In The Fair Value Hierarchy

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2013:

		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2013	$	5		$	(a)		$	5
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—			(a)			—
Total realized and unrealized gains (losses)		—			(a)			—
Purchases		1			(a)			1
Sales		—			(a)			—
Settlements		(1	)		(a)			(1	)
Ending balance at March 31, 2013	$	5		$	(a)		$	5
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2013	$	—		$	(a)		$	—
Natural gas:
Beginning balance at January 1, 2013	$	—		$	—		$	—
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—			1			1
Total realized and unrealized gains (losses)		—			1			1
Purchases		—			1			1
Ending balance at March 31, 2013	$	—		$	2		$	2
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2013	$	—		$	—		$	—
Power:
Beginning balance at January 1, 2013	$	11		$	(111	)	$	(100	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		5			14			19
Total realized and unrealized gains (losses)		5			14			19
Settlements		(13	)		16			3
Transfers into Level 3		(2	)		—			(2	)
Transfers out of Level 3		1			—			1
Ending balance at March 31, 2013	$	2		$	(81	)	$	(79	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2013	$	(3	)	$	14		$	11
Uranium:
Beginning balance at January 1, 2013	$	(2	)	$	(a)		$	(2	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—			(a)			—
Total realized and unrealized gains (losses)		—			(a)			—
Ending balance at March 31, 2013	$	(2	)	$	(a)		$	(2	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2013	$	—		$	(a)		$	—

(a) Not applicable.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2012:

		Net derivative commodity contracts
		Ameren Missouri				Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2012	$	3			$	(a)		$	3
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		2				(a)			2
Total realized and unrealized gains (losses)		2				(a)			2
Transfers into Level 3		2				(a)			2
Ending balance at March 31, 2012	$	7			$	(a)		$	7
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012	$	2			$	(a)		$	2
Natural gas:
Beginning balance at January 1, 2012	$	(14		)	$	(160	)	$	(174		)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(2		)		(26	)		(28		)
Total realized and unrealized gains (losses)		(2		)		(26	)		(28		)
Settlements		1				16			17
Transfers out of Level 3		15				170			185
Ending balance at March 31, 2012	$	—			$	—		$	—
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012	$	—			$	—		$	—
Power(b):
Beginning balance at January 1, 2012	$	21			$	(140	)	$	81
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		13				(220	)		(158		)
Total realized and unrealized gains (losses)		13				(220	)		(158		)
Settlements		(13		)		76			(4		)
Transfers out of Level 3		(1		)		—			(1		)
Ending balance at March 31, 2012	$	20			$	(284	)	$	(82		)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012	$	10			$	(202	)	(c) $	(156		)
Uranium:
Beginning balance at January 1, 2012		$	(1	)		(a)			$	(1	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—				(a)			—
Total realized and unrealized gains (losses)		—				(a)			—
Ending balance at March 31, 2012		$	(1	)		(a)			$	(1	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012		$	—			(a)			$	—

(a) Not applicable.

(b) Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company.

(c) 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.

Schedule Of Transfers Between Fair Value Hierarchy Levels

The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the three months ended March 31, 2013, and 2012:

	2013			2012
Ameren - 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	—			185
Transfers into Level 3 / Transfers out of Level 2 - Power	(2		)	—
Transfers out of Level 3 / Transfers into Level 2 - Power	1			(1		)
Net fair value of Level 3 transfers	$	(1	)	$	186
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	(2		)	—
Transfers out of Level 3 / Transfers into Level 2 - Power	1			(1		)
Net fair value of Level 3 transfers	$	(1	)	$	16
Ameren Illinois - derivative commodity contracts:
Transfers out of Level 3 / Transfers into Level 2 - Natural gas	$	—		$	170

Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt, Capital Lease Obligations And Preferred Stock

The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at March 31, 2013, and December 31, 2012:

	March 31, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:(a)(b)
Long-term debt and capital lease obligations (including current portion)	$	6,158	$	7,127	$	6,157	$	7,110
Preferred stock	142		124		142		123
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	4,006	$	4,645	$	4,006	$	4,625
Preferred stock	80		74		80		73
Ameren Illinois:
Long-term debt (including current portion)	$	1,727	$	2,027	$	1,727	$	2,020
Preferred stock	62		50		62		49

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

(b) Preferred stock along with the noncontrolling interest of EEI is recorded in “Noncontrolling Interests” on the balance sheet.

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Retirement Benefits (Summary Of Benefit Plan Costs Incurred) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Pension Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	$ 31	$ 29
Pension Benefit [Member] | Union Electric Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	18	16
Pension Benefit [Member] | Ameren Illinois Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	10	10
Pension Benefit [Member] | Other [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	3	3
Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	3	7
Postretirement Benefits [Member] | Union Electric Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	2	5
Postretirement Benefits [Member] | Ameren Illinois Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	1	2
Postretirement Benefits [Member] | Other [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost

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Divestiture Transactions and Discontinued Operations (Components of Discontinued Operations in Consolidated Statement of Income) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenues	$ 264		$ 246
Operating expenses	(415)	[1]	(826)	[2]
Operating (loss)	(151)		(580)
Other income (loss)	(2)
Interest charges	(11)		(15)
Loss before income taxes	(164)		(595)
Income tax (expense) benefit	(35)		153
Loss from discontinued operations, net of taxes	(199)		(442)
New Ameren Energy Resources Company, LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of Long-Lived Assets to be Disposed of	155
Duck Creek Energy Center [Member] | New Ameren Energy Resources Company, LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of Long-Lived Assets to be Disposed of			$ 628

[1] Includes a noncash pretax impairment charge of $155 million to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell.

[2] Includes 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 under held and used accounting guidance.

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Segment Information

3 Months Ended

Mar. 31, 2013

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

Ameren historically had three reportable segments: Ameren Missouri, Ameren Illinois, and Merchant Generation. The Ameren Missouri segment for both 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 both 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 consisted primarily of the operations or activities of AER, including Genco, EEI, AERG, and Marketing Company. Ameren is divesting its Merchant Generation segment and therefore has excluded that segment’s information below. See Note 2 - Divestiture Transactions and Discontinued Operations for information regarding the Merchant Generation segment. The category called Other primarily includes Ameren parent company activities, Ameren Services, and ATXI. The Other category also includes activities previously included in the Merchant Generation segment that will be retained by Ameren after the divestiture of New AER and the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers is complete. See Note 2 - Divestiture Transactions and Discontinued Operations for information regarding the assets and liabilities retained by Ameren after the divestitures.

The following table presents information about the revenues and specified items included in Ameren’s net income for the three months ended March 31, 2013, and 2012, and total assets as of March 31, 2013, and December 31, 2012.

Three Months	Ameren Missouri		Ameren Illinois		Other			Intersegment Eliminations			Consolidated
2013
External revenues	$	789	$	684	$	2		$	—		$	1,475
Intersegment revenues	7		—		2			(9		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	40		31		(17		)	—			54
2012
External revenues	$	686	$	724	$	2		$	—		$	1,412
Intersegment revenues	5		—		1			(6		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	21		27		(11		)	—			37
As of March 31, 2013:
Total assets	$	12,867	$	7,288	$	1,289		$	(992	)	$	20,452	(a)
As of December 31, 2012:
Total assets	$	13,043	$	7,282	$	1,228		$	(944	)	$	20,609	(a)

(a)    Excludes “Current assets of discontinued operations.” See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.