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, 2014

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) 343-8150

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 website, 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, 2014, was as follows:

Ameren Corporation	Common stock, $0.01 par value per share - 242,634,798
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 (d/b/a Ameren Missouri)	7
	Statement of Income and Comprehensive Income	7
	Balance Sheet	8
	Statement of Cash Flows	9
	Ameren Illinois Company (d/b/a Ameren Illinois)	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	44
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	61
Item 4.	Controls and Procedures	62
PART II Other Information
Item 1.	Legal Proceedings	63
Item 1A.	Risk Factors	63
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	63
Item 6.	Exhibits	63
Signatures		66

This report 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 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.

Form 10-K - The combined Annual Report on Form 10-K for the year ended December 31, 2013, filed by the Ameren Companies with the SEC. 

NEIL - Nuclear Electric Insurance Limited, which includes all of its affiliated companies.

FORWARD-LOOKING STATEMENTS

Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed under Risk Factors in the Form 10-K, and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:

• regulatory, judicial, or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the complaint cases filed by Noranda and 37 residential customers with the MoPSC in February 2014; the outcome of Ameren Illinois' appeals of the ICC's electric and natural gas rate orders issued in December 2013; Ameren Illinois' request for rehearing of a July 2012 FERC order regarding the inclusion of acquisition premiums in its transmission rates; the complaint case filed with FERC seeking a reduction in the allowed return on common equity under the MISO tariff; 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, including the direct relationship between Ameren Illinois' return on common equity and the 30-year United States Treasury bond yields, 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 Ameren Illinois' expected participation, beginning in 2015, in the regulatory framework provided by the state of Illinois' Natural Gas Consumer, Safety and Reliability Act, which allows for the use of a rider to recover costs of certain natural gas infrastructure investments made between rate cases;

• the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our business at either the state or federal levels and the implementation of deregulation;

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

• 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 timely recover these costs;

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

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

• 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 may make the Ameren Companies' access to necessary capital, including short-term credit and liquidity, impossible, more difficult, or more costly;

• our assessment of our liquidity;

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

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

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

1

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

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

• the impact of current environmental regulations on utilities and power generating companies and new, more stringent or changing requirements, including those related to greenhouse gases, other emissions 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, cause us to sell 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 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 Missouri's energy centers or required to satisfy Ameren Missouri’s energy sales;

• the inability of Dynegy and IPH to satisfy their indemnity and other obligations to Ameren in connection with the divestiture of New AER to IPH;

• legal and administrative proceedings; and

• acts of sabotage, war, terrorism, cyber 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,
	2014			2013
Operating Revenues:
Electric	$	1,106		$	1,088
Gas	488			387
Total operating revenues	1,594			1,475
Operating Expenses:
Fuel	204			213
Purchased power	112			151
Gas purchased for resale	304			230
Other operations and maintenance	420			399
Depreciation and amortization	181			175
Taxes other than income taxes	127			122
Total operating expenses	1,348			1,290
Operating Income	246			185
Other Income and Expenses:
Miscellaneous income	18			15
Miscellaneous expense	9			8
Total other income	9			7
Interest Charges	92			101
Income Before Income Taxes	163			91
Income Taxes	64			35
Income from Continuing Operations	99			56
Loss from Discontinued Operations, Net of Taxes (Note 12)	(1		)	(199		)
Net Income (Loss)	98			(143		)
Less: Net Income from Continuing Operations Attributable to Noncontrolling Interests	2			2
Net Income (Loss) Attributable to Ameren Corporation:
Continuing Operations	97			54
Discontinued Operations	(1		)	(199		)
Net Income (Loss) Attributable to Ameren Corporation	$	96		$	(145	)
Earnings (Loss) per Common Share – Basic:
Continuing Operations	$	0.40		$	0.22
Discontinued Operations	—			(0.82		)
Earnings (Loss) per Common Share – Basic	$	0.40		$	(0.60	)
Dividends per Common Share	$	0.40		$	0.40
Average Common Shares Outstanding – Basic	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,
	2014			2013
Income from Continuing Operations	$	99		$	56
Other Comprehensive Income, Net of Taxes	—			—
Comprehensive Income from Continuing Operations	99			56
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests	2			2
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation	97			54
Loss from Discontinued Operations, Net of Taxes	(1		)	(199		)
Other Comprehensive Loss from Discontinued Operations, Net of Taxes	—			(7		)
Comprehensive Loss from Discontinued Operations Attributable to Ameren Corporation	(1		)	(206		)
Comprehensive Income (Loss) Attributable to Ameren Corporation	$	96		$	(152	)

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, 2014		December 31, 2013
ASSETS
Current Assets:
Cash and cash equivalents	$	26	$	30
Accounts receivable – trade (less allowance for doubtful accounts of $26 and $18, respectively)	553		404
Unbilled revenue	236		304
Miscellaneous accounts and notes receivable	201		196
Materials and supplies	424		526
Current regulatory assets	220		156
Current accumulated deferred income taxes, net	95		106
Other current assets	70		85
Assets of discontinued operations (Note 12)	15		165
Total current assets	1,840		1,972
Property and Plant, Net	16,425		16,205
Investments and Other Assets:
Nuclear decommissioning trust fund	503		494
Goodwill	411		411
Intangible assets	17		22
Regulatory assets	1,251		1,240
Other assets	719		698
Total investments and other assets	2,901		2,865
TOTAL ASSETS	$	21,166	$	21,042
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	648	$	534
Short-term debt	700		368
Accounts and wages payable	559		806
Taxes accrued	89		55
Interest accrued	104		86
Current regulatory liabilities	248		216
Other current liabilities	344		351
Liabilities of discontinued operations (Note 12)	33		45
Total current liabilities	2,725		2,461
Long-term Debt, Net	5,226		5,504
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	3,340		3,250
Accumulated deferred investment tax credits	62		63
Regulatory liabilities	1,751		1,705
Asset retirement obligations	373		369
Pension and other postretirement benefits	480		466
Other deferred credits and liabilities	554		538
Total deferred credits and other liabilities	6,560		6,391
Commitments and Contingencies (Notes 2, 9, 10 and 12)
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	5,602		5,632
Retained earnings	906		907
Accumulated other comprehensive income	3		3
Total Ameren Corporation stockholders’ equity	6,513		6,544
Noncontrolling Interests	142		142
Total equity	6,655		6,686
TOTAL LIABILITIES AND EQUITY	$	21,166	$	21,042

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,
	2014			2013
Cash Flows From Operating Activities:
Net income (loss)	$	98		$	(143	)
Loss from discontinued operations, net of taxes	1			199
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	176			166
Amortization of nuclear fuel	24			20
Amortization of debt issuance costs and premium/discounts	5			6
Deferred income taxes and investment tax credits, net	84			40
Allowance for equity funds used during construction	(7		)	(8		)
Stock-based compensation costs	9			9
Other	(1		)	(3		)
Changes in assets and liabilities:
Receivables	(86		)	(95		)
Materials and supplies	102			127
Accounts and wages payable	(183		)	(127		)
Taxes accrued	18			41
Assets, other	(90		)	52
Liabilities, other	49			29
Pension and other postretirement benefits	30			3
Counterparty collateral, net	10			26
Net cash provided by operating activities – continuing operations	239			342
Net cash provided by operating activities – discontinued operations	—			37
Net cash provided by operating activities	239			379
Cash Flows From Investing Activities:
Capital expenditures	(442		)	(275		)
Nuclear fuel expenditures	(10		)	(11		)
Purchases of securities – nuclear decommissioning trust fund	(186		)	(35		)
Sales and maturities of securities – nuclear decommissioning trust fund	182			32
Proceeds from note receivable – Marketing Company	56			—
Contributions to note receivable – Marketing Company	(65		)	—
Other	—			(2		)
Net cash used in investing activities – continuing operations	(465		)	(291		)
Net cash provided by (used in) investing activities – discontinued operations	152			(12		)
Net cash used in investing activities	(313		)	(303		)
Cash Flows From Financing Activities:
Dividends on common stock	(97		)	(97		)
Dividends paid to noncontrolling interest holders	(2		)	(2		)
Short-term debt, net	332			—
Redemptions of long-term debt	(163		)	—
Net cash provided by (used in) financing activities – continuing operations	70			(99		)
Net cash used in financing activities – discontinued operations	—			—
Net cash provided by (used in) financing activities	70			(99		)
Net change in cash and cash equivalents	(4		)	(23		)
Cash and cash equivalents at beginning of year	30			209
Cash and cash equivalents at end of period	26			186
Less cash and cash equivalents at end of period – discontinued operations	—			25
Cash and cash equivalents at end of period – continuing operations	$	26		$	161

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

6

UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)

	Three Months Ended March 31,
	2014		2013
Operating Revenues:
Electric	$	749	$	732
Gas	68		64
Total operating revenues	817		796
Operating Expenses:
Fuel	204		213
Purchased power	33		26
Gas purchased for resale	40		37
Other operations and maintenance	227		221
Depreciation and amortization	116		111
Taxes other than income taxes	78		77
Total operating expenses	698		685
Operating Income	119		111
Other Income and Expenses:
Miscellaneous income	14		14
Miscellaneous expense	4		5
Total other income	10		9
Interest Charges	52		60
Income Before Income Taxes	77		60
Income Taxes	29		19
Net Income	48		41
Other Comprehensive Income	—		—
Comprehensive Income	$	48	$	41
Net Income	$	48	$	41
Preferred Stock Dividends	1		1
Net Income Available to Common Stockholder	$	47	$	40

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

7

UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)

BALANCE SHEET

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

	March 31, 2014		December 31, 2013
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	1
Accounts receivable – trade (less allowance for doubtful accounts of $7 and $5, respectively)	218		191
Accounts receivable – affiliates	1		1
Unbilled revenue	129		168
Miscellaneous accounts and notes receivable	67		57
Materials and supplies	338		352
Current regulatory assets	145		118
Other current assets	50		71
Total current assets	948		959
Property and Plant, Net	10,499		10,452
Investments and Other Assets:
Nuclear decommissioning trust fund	503		494
Intangible assets	17		22
Regulatory assets	539		534
Other assets	442		443
Total investments and other assets	1,501		1,493
TOTAL ASSETS	$	12,948	$	12,904
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	223	$	109
Borrowings from money pool	—		105
Short-term debt	290		—
Accounts and wages payable	183		387
Accounts payable – affiliates	38		30
Taxes accrued	252		220
Interest accrued	47		57
Current regulatory liabilities	47		57
Other current liabilities	87		82
Total current liabilities	1,167		1,047
Long-term Debt, Net	3,535		3,648
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	2,551		2,524
Accumulated deferred investment tax credits	58		59
Regulatory liabilities	1,062		1,041
Asset retirement obligations	371		366
Pension and other postretirement benefits	198		189
Other deferred credits and liabilities	43		37
Total deferred credits and other liabilities	4,283		4,216
Commitments and Contingencies (Notes 2, 8, 9 and 10)
Stockholders’ Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding	511		511
Other paid-in capital, principally premium on common stock	1,560		1,560
Preferred stock not subject to mandatory redemption	80		80
Retained earnings	1,812		1,842
Total stockholders’ equity	3,963		3,993
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	12,948	$	12,904

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

8

UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Three Months Ended March 31,
	2014			2013
Cash Flows From Operating Activities:
Net income	$	48		$	41
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	112			104
Amortization of nuclear fuel	24			20
Amortization of debt issuance costs and premium/discounts	2			2
Deferred income taxes and investment tax credits, net	30			(8		)
Allowance for equity funds used during construction	(7		)	(7		)
Changes in assets and liabilities:
Receivables	2			(50		)
Materials and supplies	14			22
Accounts and wages payable	(153		)	(139		)
Taxes accrued	30			38
Assets, other	(28		)	38
Liabilities, other	7			5
Pension and other postretirement benefits	15			2
Net cash provided by operating activities	96			68
Cash Flows From Investing Activities:
Capital expenditures	(188		)	(137		)
Nuclear fuel expenditures	(10		)	(11		)
Money pool advances, net	—			24
Purchases of securities – nuclear decommissioning trust fund	(186		)	(35		)
Sales and maturities of securities – nuclear decommissioning trust fund	182			32
Other	(2		)	(2		)
Net cash used in investing activities	(204		)	(129		)
Cash Flows From Financing Activities:
Dividends on common stock	(77		)	(90		)
Dividends on preferred stock	(1		)	(1		)
Short-term debt, net	290			—
Money pool borrowings, net	(105		)	5
Net cash provided by (used in) financing activities	107			(86		)
Net change in cash and cash equivalents	(1		)	(147		)
Cash and cash equivalents at beginning of year	1			148
Cash and cash equivalents at end of period	$	—		$	1

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

9

AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)

	Three Months Ended March 31,
	2014			2013
Operating Revenues:
Electric	$	353		$	360
Gas	421			324
Total operating revenues	774			684
Operating Expenses:
Purchased power	81			127
Gas purchased for resale	264			193
Other operations and maintenance	200			176
Depreciation and amortization	63			61
Taxes other than income taxes	46			42
Total operating expenses	654			599
Operating Income	120			85
Other Income and Expenses:
Miscellaneous income	3			1
Miscellaneous expense	4			3
Total other expense	(1		)	(2		)
Interest Charges	30			31
Income Before Income Taxes	89			52
Income Taxes	35			20
Net Income	54			32
Other Comprehensive Loss, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(1) and $(1), respectively	(1		)	(1		)
Comprehensive Income	$	53		$	31
Net Income	$	54		$	32
Preferred Stock Dividends	1			1
Net Income Available to Common Stockholder	$	53		$	31

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

10

AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)

BALANCE SHEET

(Unaudited) (In millions)

	March 31, 2014		December 31, 2013
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable – trade (less allowance for doubtful accounts of $18 and $13, respectively)	328		201
Unbilled revenue	107		135
Miscellaneous accounts receivable	8		13
Materials and supplies	86		174
Current regulatory assets	75		38
Current accumulated deferred income taxes, net	52		45
Other current assets	20		26
Total current assets	677		633
Property and Plant, Net	5,731		5,589
Investments and Other Assets:
Goodwill	411		411
Regulatory assets	706		701
Other assets	115		120
Total investments and other assets	1,232		1,232
TOTAL ASSETS	$	7,640	$	7,454
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Borrowings from money pool	$	242	$	56
Accounts and wages payable	230		243
Accounts payable – affiliates	28		18
Taxes accrued	22		23
Customer deposits	80		79
Current environmental remediation	46		43
Current regulatory liabilities	201		159
Other current liabilities	153		150
Total current liabilities	1,002		771
Long-term Debt, Net	1,692		1,856
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,158		1,116
Accumulated deferred investment tax credits	4		4
Regulatory liabilities	689		664
Pension and other postretirement benefits	200		197
Environmental remediation	222		232
Other deferred credits and liabilities	173		166
Total deferred credits and other liabilities	2,446		2,379
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholders’ Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding	—		—
Other paid-in capital	1,965		1,965
Preferred stock not subject to mandatory redemption	62		62
Retained earnings	463		410
Accumulated other comprehensive income	10		11
Total stockholders’ equity	2,500		2,448
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	7,640	$	7,454

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

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AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Three Months Ended March 31,
	2014			2013
Cash Flows From Operating Activities:
Net income	$	54		$	32
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	62			60
Amortization of debt issuance costs and premium/discounts	3			3
Deferred income taxes and investment tax credits, net	36			50
Other	(2		)	(1		)
Changes in assets and liabilities:
Receivables	(94		)	(58		)
Materials and supplies	88			105
Accounts and wages payable	14			9
Taxes accrued	(1		)	3
Assets, other	(61		)	16
Liabilities, other	71			24
Pension and other postretirement benefits	10			1
Counterparty collateral, net	12			27
Net cash provided by operating activities	192			271
Cash Flows From Investing Activities:
Capital expenditures	(215		)	(133		)
Money pool advances, net	—			(5		)
Other	1			—
Net cash used in investing activities	(214		)	(138		)
Cash Flows From Financing Activities:
Dividends on common stock	—			(15		)
Dividends on preferred stock	(1		)	(1		)
Money pool borrowings, net	186			(24		)
Redemptions of long-term debt	(163		)	—
Net cash provided by (used in) financing activities	22			(40		)
Net change in cash and cash equivalents	—			93
Cash and cash equivalents at beginning of year	1			—
Cash and cash equivalents at end of period	$	1		$	93

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

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AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY (d/b/a Ameren Missouri)

AMEREN ILLINOIS COMPANY (d/b/a Ameren Illinois)

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

March 31, 2014

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. 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, doing business as 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 Missouri supplies electric service to 1.2 million customers and natural gas service to 127,000 customers.

• Ameren Illinois Company, doing business as Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 807,000 customers.

Ameren has various other subsidiaries responsible for activities such as the provision of shared services. Ameren also has a subsidiary, ATXI, that operates a FERC rate-regulated electric transmission business and is developing the Illinois Rivers project.

The operating results, assets, and liabilities for New AER and the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers have been presented separately as

discontinued operations for all periods presented in this report. Unless otherwise stated, these notes to Ameren’s financial statements exclude discontinued operations for all periods presented. On January 31, 2014, Medina Valley completed its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. See Note 12 - Divestiture Transactions and Discontinued Operations in this report for additional information regarding the discontinued operations presentation and Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information regarding Ameren’s divestiture of New AER in December 2013.

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. Ameren Missouri and Ameren Illinois have no subsidiaries, and therefore their financial statements are not prepared on a consolidated basis. 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, 2014, and 2013, caused by the assumed settlement of performance share units. The number of dilutive performance share units had an immaterial impact on earnings per share.

Stock-based Compensation

Ameren’s long-term incentive plan available for eligible employees, the 2006 Omnibus Incentive Compensation Plan (2006 Plan), was replaced prospectively for new grants only by the 2014 Omnibus Incentive Compensation Plan (2014 Plan) effective April 24, 2014. The 2014 Plan provides for a maximum of 8 million common shares to be available for grant to eligible employees and directors, and retains many of the features of the 2006 Plan. The 2014 Plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards.

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A summary of nonvested performance share units at March 31, 2014, and changes during the three months ended March 31, 2014, under the 2006 Plan are presented below:

	Performance Share Units
	Share Units		Weighted-average Fair Value Per Unit at Grant Date
Nonvested at January 1, 2014	1,218,544		$	33.23
Granted(a)	680,606		38.90
Forfeitures	(46,758	)	33.29
Vested(b)	(116,297	)	38.81
Nonvested at March 31, 2014	1,736,095		$	35.08

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2014 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 2014 under the 2006 Plan was determined to be $38.90. That amount was based on Ameren’s closing common share price of $36.16 at December 31, 2013, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total stockholder return for a three-year performance period relative to the designated peer group beginning January 1, 2014. 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 0.78%, volatility of 12% to 18% 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 renewable energy credits and emission allowances 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, 2014, 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 $17 million each at March 31, 2014. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $22 million each at December 31, 2013.

Ameren Missouri’s and Ameren Illinois’ renewable energy credits and Ameren Missouri’s emission allowances are charged to “Purchased power” expense and “Fuel” expense, respectively, as they are used in operations. The following table presents amortization expense based on usage of renewable energy credits and emission allowances, net of gains from sales, for Ameren, Ameren Missouri and Ameren Illinois, during the three months ended March 31, 2014, and 2013:

	Three Months
	2014			2013
Ameren Missouri	$	6	(a)	$	(b)
Ameren Illinois		3			4
Ameren	$	9		$	4

(a) Includes higher priced renewable energy credits. 

(b) 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 customer and are therefore not included in revenues and expenses. They are 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, 2014, and 2013:

	Three months
	2014		2013
Ameren Missouri	$	34	$	33
Ameren Illinois	26		22
Ameren	$	60	$	55

Uncertain Tax Positions

The following table presents the amount of unrecognized tax benefits (detriments) as of March 31, 2014, and December 31, 2013:

	March 31, 2014			December 31, 2013
Ameren	$	92		$	90
Ameren Missouri	32			31
Ameren Illinois	(1		)	(1		)

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With the adoption of new accounting guidance in the first quarter of 2014, unrecognized tax benefits are recorded in “Accumulated deferred income taxes, net” as a reduction to the deferred tax assets for net operating loss and tax credit carryforwards on Ameren’s, Ameren Missouri’s and Ameren Illinois’ balance sheets. Unrecognized tax benefits that exceed these carryforwards are recorded in “Other deferred credits and liabilities” on the respective balance sheets. At March 31, 2014, unrecognized tax benefits of $84 million, $14 million, and $- million were recorded in “Accumulated deferred income taxes, net” on Ameren's, Ameren Missouri's and Ameren Illinois' balance sheets, respectively. At December 31, 2013, unrecognized tax benefits of $84 million, $15 million, and $- million previously recorded in “Other deferred credits and liabilities” on the respective balance sheets were reclassified to “Accumulated deferred income taxes, net” for comparative purposes. For additional information see the Accounting and Reporting Developments section below.

The following table presents the amount of unrecognized tax benefits (detriments) as of March 31, 2014, and 2013, that would impact the effective tax rate, if recognized:

	March 31, 2014			December 31, 2013
Ameren	$	55		$	54
Ameren Missouri	2			3
Ameren Illinois	(1		)	—

Ameren’s federal income tax returns for the years 2007 through 2011 are before the Appeals Office of the IRS. Ameren’s federal income tax return for the year 2012 is currently under examination.

It is reasonably possible that a settlement will be reached with the Appeals Office of the IRS in the next 12 months for the years 2007 through 2011. This settlement, which is primarily related to uncertain tax positions for research tax deductions, is expected to result in a decrease in uncertain tax benefits of $20 million and $13 million for Ameren and Ameren Missouri, 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 at March 31, 2014, compared to December 31, 2013, to reflect the accretion of obligations to their fair value, partially offset by immaterial settlements.

Noncontrolling Interests

As of March 31, 2014, Ameren's noncontrolling interests were composed of the preferred stock not subject to mandatory redemption of Ameren Missouri and Ameren Illinois. All noncontrolling interests are classified as a component of equity separate from Ameren's equity on its consolidated balance sheet. A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren for the three months ended March 31, 2014, and 2013, are shown below:

	Three Months
	2014			2013
Noncontrolling interests, beginning of period	$	142		$	151		(a)
Net income from continuing operations attributable to noncontrolling interests	2			2
Dividends paid to noncontrolling interest holders	(2		)	(2		)
Noncontrolling interests, end of period	$	142		$	151		(a)

(a) Included the 20% EEI ownership interest not owned by Ameren prior to the divestiture of New AER to IPH. Prior to the divestiture of New AER, the assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Assets of discontinued operations” and “Liabilities of discontinued operations.” The divestiture of New AER, which included EEI, was completed in the fourth quarter of 2013. See Note 12 - Divestiture Transactions and Discontinued Operations for additional information.

Accounting and Reporting Developments

The following is a summary of recently adopted authoritative accounting guidance.

Presentation of an Unrecognized Tax Benefit

In July 2013, FASB issued additional authoritative

accounting guidance to provide clarity for the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The objective of this guidance is to eliminate diversity in practice related to the presentation of certain unrecognized tax benefits. It requires entities to present an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating

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loss carryforward, a similar tax loss, or a tax credit carryforward to the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is available under the tax law. This guidance was effective for the Ameren Companies beginning in the first quarter of 2014. Previously, unrecognized tax benefits were recorded in “Other deferred credits and liabilities” on Ameren's, Ameren Missouri's and Ameren Illinois' balance sheets. Beginning in the first quarter 2014, unrecognized tax benefits are recorded in “Accumulated deferred income taxes, net” as a reduction to the deferred tax assets for net operating loss and tax credit carryforwards on the respective balance sheets. Unrecognized tax benefits that exceed these carryforwards are recorded in “Other deferred credits and liabilities,” on the respective balance sheets. For comparative purposes, the Ameren Companies reclassified the December 31, 2013 balances in accordance with the new guidance as discussed in the Uncertain Tax Positions section above. The implementation of the additional authoritative accounting guidance did not affect the Ameren Companies' results of operations or liquidity, as this guidance is presentation-related only.

NOTE 2 - 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

Accounting Authority Order

In July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren Missouri to defer fixed costs totaling $36 million that were not previously 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. In November 2013, the MoPSC issued an order approving Ameren Missouri’s request for an accounting authority order, which will allow Ameren Missouri to seek recovery of these fixed costs in a future electric rate case. Ameren Missouri will seek to recover these fixed costs in its next electric rate case, which it will file by July 15, 2014. In February 2014, MIEC and MoOPC filed appeals of the accounting authority order to the Missouri Court of Appeals, Western District.

Earnings Complaint and Rate Shift Complaint Cases

In February 2014, Ameren Missouri’s largest customer, Noranda, and 37 residential customers filed an earnings complaint case and a rate shift complaint case with the MoPSC. In the earnings complaint case, Noranda and the residential customers asserted that Ameren Missouri’s electric service business is earning more than the 9.8% return on equity authorized in the MoPSC's December 2012 electric rate order and requested that the MoPSC approve a $67 million reduction to

Ameren Missouri’s annual revenue requirement. Included in Noranda’s request is a reduction of Ameren Missouri’s authorized return on equity to 9.4%. The rate shift complaint case seeks to reduce Noranda’s electricity cost with an offsetting increase in electricity cost for Ameren Missouri’s other customers. While the rate shift proposal is revenue neutral to Ameren Missouri, Ameren Missouri does not believe that the proposed reduction to Noranda’s electric rates, which are significantly below Ameren Missouri’s cost of service, is appropriate or in the best interests of Ameren Missouri’s other electric customers. The MoOPC and MIEC have intervened in the earnings complaint case.

While the MoPSC has no time requirement by which it must issue an order in these cases, it has adopted procedural schedules that would render a decision in the rate shift case by August 6, 2014, and in the earnings complaint case by September 26, 2014. Ameren Missouri does not believe that a reduction in electric service rates is justified and will file testimony that supports that position, which is consistent with Ameren Missouri’s expected July 2014 rate case filing. The MoPSC has 11 months from when Ameren Missouri files its request to issue an order.

Illinois

IEIMA

Under the provisions of the IEIMA, Ameren Illinois’ electric delivery service rates are subject to an annual revenue requirement reconciliation to its actual costs. Throughout each year, Ameren Illinois records a regulatory asset or a regulatory liability and a corresponding increase or decrease to operating revenues for any differences between the revenue requirement in effect for that year and its estimate of the probable increase or decrease in the revenue requirement expected to ultimately be approved by the ICC based on that year's actual costs incurred. As of March 31, 2014, Ameren Illinois had recorded a regulatory asset of $24 million to reflect its expected 2014 revenue requirement reconciliation adjustment, with interest.

In September 2012 and December 2012, the ICC issued orders in Ameren Illinois’ IEIMA performance-based formula rate filings. Ameren Illinois appealed both orders to the Appellate Court of the Fourth District of Illinois. The primary issues Ameren Illinois appealed were the rate treatment of accumulated deferred income taxes and vacation obligations as well as the calculation of Ameren Illinois’ capital structure. In December 2013, the appellate court rendered its decision upholding the ICC’s September and December 2012 orders. Ameren Illinois filed an appeal to the Illinois Supreme Court in March 2014.

In December 2013, the ICC issued an order in Ameren Illinois' annual update filing, which was based on 2012 recoverable costs and expected net plant additions for 2013. The ICC order established rates for 2014. In February 2014, Ameren Illinois filed an appeal to the Appellate Court of the Fourth District of Illinois regarding the calculation of its capital structure and the rate treatment of accumulated deferred income taxes related to the transfer of former Ameren Missouri assets in Illinois to Ameren Illinois.

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In April 2014, Ameren Illinois filed with the ICC its annual electric delivery service formula rate update to establish the revenue requirement used to set rates for 2015. Pending ICC approval, Ameren Illinois’ update filing will result in a $206 million increase in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2015. This update reflects an increase to the annual formula rate based on 2013 actual costs and expected net plant additions for 2014; an increase to include the annual reconciliation of the revenue requirement in effect for 2013 to the actual costs incurred in that year; and an increase resulting from the conclusion of a refund to customers in 2014 for the 2012 revenue requirement reconciliation. An ICC decision on this April 2014 filing is expected by December 2014.

2013 Natural Gas Delivery Service Rate Case

In December 2013, the ICC issued a rate order that approved an increase in revenues for natural gas delivery service of $32 million. The revenue increase was based on a 9.1% return on equity, a capital structure composed of 51.7% common equity, and a rate base of $1.1 billion. The rate order was based on a 2014 future test year. The rate changes became effective January 1, 2014. In March 2014, Ameren Illinois filed an appeal of the allowed return on equity included in the ICC's order with the Appellate Court of the Fourth District of Illinois. Ameren Illinois sought a 10.4% return on equity in this rate case.

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 a settlement with four of its nine wholesale customers, which have been approved by FERC and refunds have been issued. The impasse with the remaining five wholesale customers is awaiting final FERC action. In November 2012, a FERC administrative law judge issued an initial decision, which is now pending before FERC. The timing of a decision from FERC is uncertain and subsequent appeals are possible. In accordance with the administrative law judge's initial decision, Ameren and Ameren Illinois have both included on their balance sheets in “Current regulatory liabilities” an estimate of $14 million and $13 million as of March 31, 2014, and December 31, 2013, respectively, for the refund due to the remaining wholesale customers relating to billings for the period from March 2011 through March 2014.

Ameren Illinois Electric Transmission Rate Refund

In July 2012, FERC issued an order concluding that Ameren Illinois improperly included acquisition premiums, primarily goodwill, in determining the common equity used in its electric transmission formula rate, and thereby inappropriately recovered a higher amount 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 a 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.

Ameren Illinois submitted a refund report in November 2012 and concluded that no refund was warranted. Several wholesale customers filed a protest with FERC regarding Ameren's conclusion that no refund was warranted. In June 2013, FERC issued an order that rejected Ameren Illinois' November 2012 refund report and provided guidance as to the filing of a new refund report. In July 2013, Ameren Illinois filed a revised refund report based on the guidance provided in the June 2013 order, as well as a request for a rehearing of that order. Ameren Illinois' July 2013 refund report also concluded that no refund was warranted. Ameren Illinois estimated the maximum pretax charge to earnings for this possible refund obligation through December 31, 2014 would be $19 million, before interest charges. 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.

FERC Complaint Case

In November 2013, a customer group filed a complaint case with FERC seeking a reduction in the allowed return on common equity to 9.15%, as well as a limit on the common equity ratio, under the MISO tariff. Currently, the FERC-allowed return on common equity for MISO transmission owners is 12.38%. This complaint case could result in a reduction to Ameren Illinois' and ATXI's allowed return on common equity. That reduction could also result in a refund for transmission service revenues earned after the filing of the complaint case in November 2013. FERC has not issued an order in this case, and it is under no deadline to do so. Ameren is not able to predict if or how FERC will rule on this complaint case.

Ameren Missouri Power Purchase Agreement with Entergy

Beginning in 2005, FERC issued a series of orders addressing a complaint filed in 2001 by the Louisiana Public Service Commission against Entergy and certain of its affiliates. The complaint alleged unjust and unreasonable cost allocations. As a result of the FERC orders, Entergy began billing Ameren Missouri in 2007 for additional charges under a 165-megawatt power purchase agreement, which expired August 31, 2009. In May 2012, FERC issued an order stating that Entergy should not have included additional charges to Ameren Missouri under the power purchase agreement. Pursuant to the order, in June 2012, Entergy paid Ameren Missouri $31 million. In July 2012, Entergy filed an appeal of FERC's January 2010 and May 2012 orders to the United States Court of Appeals for the District of Columbia Circuit, which was subsequently dismissed on a procedural issue. In November 2013, Entergy refiled the appeal of FERC's May 2012 order with the United States Court of Appeals for the District of Columbia Circuit. Ameren is not able to predict when or how the court will rule on Entergy's appeal.

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The Louisiana Public Service Commission appealed FERC’s orders regarding Louisiana Public Service Commission’s complaint against Entergy Services, Inc. to the United States Court of Appeals for the District of Columbia Circuit. In April 2008, that court ordered further FERC proceedings regarding Louisiana Public Service Commission’s complaint. The court ordered FERC to explain its previous denial of retroactive refunds and the implementation of prospective charges. FERC’s decision on remand of the retroactive impact of these issues could have a financial impact on Ameren Missouri. Ameren Missouri is unable to predict when or how FERC will respond to the court’s decisions. Ameren Missouri estimates that it could incur an additional expense of up to $25 million if FERC orders retroactive application for the years 2001 to 2005. Ameren Missouri believes that the likelihood of incurring any expense is not probable, and therefore no liability has been recorded as of March 31, 2014.

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.

Ameren Missouri estimated the total cost required to obtain a small modular reactor COL to be $80 million to $100 million. As of March 31, 2014, Ameren Missouri had capitalized investments of $69 million for the development of a new nuclear energy center. Ameren Missouri is currently evaluating all potential nuclear technologies in order to maintain an option for nuclear power in the future.

All of Ameren Missouri's capitalized investments for the development of a new nuclear energy center will remain capitalized while management pursues options to maximize the value of its investment. If efforts to license additional nuclear generation are 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 3 - SHORT-TERM DEBT AND LIQUIDITY

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

The 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement, both of which expire on November 14, 2017, were not utilized for direct borrowings during the three months ended March 31, 2014, but they were used to support commercial paper issuances and to issue letters of credit. As of March 31, 2014, based on letters of credit issued under the 2012 Credit Agreements, as well as commercial paper outstanding, the aggregate amount of credit capacity available to Ameren (parent), Ameren Missouri and Ameren Illinois, collectively, at March 31, 2014, was $1.4 billion.

Commercial Paper

Ameren (parent) had $410 million and $368 million of commercial paper outstanding at March 31, 2014, and December 31, 2013, respectively. Ameren Missouri had $290 million and $- million of commercial paper outstanding at March 31, 2014, and December 31, 2013, respectively.

The following table summarizes the commercial paper activity and relevant interest rates under Ameren’s (parent) and Ameren Missouri’s commercial paper programs for the three months ended March 31, 2014, and 2013:

	Ameren (parent)			Ameren Missouri			Ameren Consolidated
2014
Average daily commercial paper outstanding	$	339		$	200		$	539
Weighted-average interest rate	0.45		%	0.45		%	0.45		%
Peak commercial paper during period(a)	$	452		$	290		$	700
Peak interest rate	0.75		%	0.70		%	0.75		%
2013
Average daily commercial paper outstanding	$	2		$	—		$	2
Weighted-average interest rate	0.80		%	—		%	0.80		%
Peak commercial paper during period(a)	$	21		$	—		$	21
Peak interest rate	0.85		%	—		%	0.85		%

(a) The timing of peak commercial paper issuances varies by company, and therefore the amounts presented by company might not equal the Ameren Consolidated peak commercial paper issuances for the period.

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 under Part II, Item 8, in the Form

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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, 2014, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2012 Credit Agreements, were 50%, 49% and 44%, 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 at least 2.0 to 1.0, 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, 2014, was 5.6 to 1.0. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2012 Credit Agreement. The calculation of Ameren’s ratios discussed above includes both continuing and discontinued operations.

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. The Ameren Companies were in compliance with the provisions and covenants of their credit agreements at March 31, 2014.

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. Ameren Services is responsible for the operation and administration of the money pool agreements.

Ameren Missouri, Ameren Illinois and Ameren Services may participate in the utility money pool as both lenders and borrowers. Ameren may participate in the money pools only as a lender. Surplus internal funds are contributed to the money pool from participants. The primary sources of external funds for the money pool are the 2012 Credit Agreements and the commercial paper programs. The total amount available to the pool participants from the 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 money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. Participants receiving a loan under the 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 money pool. The average interest rate for borrowing under the utility money pool for the three months ended March 31, 2014, was 0.39% (2013 - 0.11%).

See Note 8 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three months ended March 31, 2014, and 2013.

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren Missouri

In April 2014, Ameren Missouri issued $350 million of 3.50% senior secured notes due April 15, 2024, with interest payable semiannually on April 15 and October 15 of each year, beginning October 15, 2014. Ameren Missouri received $348 million. The proceeds were used to repay a portion of its short-term debt and will be used to repay at maturity $104 million of its 5.50% senior secured notes due May 15, 2014.

Ameren Illinois

In January 2014, Ameren Illinois redeemed the following environmental improvement and pollution control revenue bonds at par value plus accrued interest:

Environmental improvement and pollution control revenue bonds	Principal Amount
5.90% Series 1993 due 2023(a)	$	32
5.70% 1994A Series due 2024(a)	36
1993 Series C-1 5.95% due 2026	35
1993 Series C-2 5.70% due 2026	8
5.40% 1998A Series due 2028	19
5.40% 1998B Series due 2028	33
Total amount redeemed	$	163

(a) Less than $1 million principal amount of the bonds remain outstanding after redemption.

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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, 2014, at an assumed annual 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	$	4,018		≥2.5	118.8	$	2,272
Ameren Illinois	≥2.0	7.6		3,732	(d)	≥1.5	2.7		203	(e)

(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 $729 million and $454 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.

(e) Preferred stock issuable is restricted by the amount of preferred stock that is currently authorized by Ameren Illinois’ articles of incorporation.

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.” 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. As of March 31, 2014, Ameren Illinois’ ratio of common stock equity to total capitalization was 55%.

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, 2014, 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. See Note - 12 Divestiture Transactions and Discontinued Operations for Ameren (parent) guarantees and letters of credit issued to support New AER based on the transaction agreement with IPH.

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NOTE 5 - 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, 2014, and 2013:

	Three Months
	2014		2013
Ameren:(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	7	$	8
Interest income on industrial development revenue bonds	7		7
Interest and dividend income	2		—
Other	2		—
Total miscellaneous income	$	18	$	15
Miscellaneous expense:
Donations	$	5	$	4
Other	4		4
Total miscellaneous expense	$	9	$	8
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	7	$	7
Interest income on industrial development revenue bonds	7		7
Total miscellaneous income	$	14	$	14
Miscellaneous expense:
Donations	$	2	$	2
Other	2		3
Total miscellaneous expense	$	4	$	5
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	—	$	1
Interest and dividend income	2		—
Other	1		—
Total miscellaneous income	$	3	$	1
Miscellaneous expense:
Donations	$	3	$	3
Other	1		—
Total miscellaneous expense	$	4	$	3

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

NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

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

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

• market values of 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 for derivative assets and liabilities as of March 31, 2014, and December 31, 2013. As of March 31, 2014, these contracts ran through October 2016, October 2019, May 2032, and October 2016 for fuel oils, natural gas, power, and uranium, respectively.

	Quantity (in millions, except as indicated)
	2014			2013
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)(a)	53	(b)	53	66	(b)	66
Natural gas (in mmbtu)	28	109	137	28	108	136
Power (in megawatthours)	2	11	13	3	11	14
Uranium (pounds in thousands)	827	(b)	827	796	(b)	796

(a) Fuel oils consist of ultra-low-sulfur diesel, on-highway diesel, and crude oil.

(b) Not applicable.

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 7 - Fair Value Measurements for a discussion of 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. 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 losses and gains 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. As of March 31, 2014, and December 31, 2013, all contracts that qualify for hedge accounting received regulatory deferral.

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.

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The following table presents the carrying value and balance sheet location of all derivative instruments as of March 31, 2014, and December 31, 2013:

	Balance Sheet Location	Ameren Missouri		Ameren Illinois		Ameren
2014
Derivative assets not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current assets	$	5	$	—	$	5
	Other assets	1		—		1
Natural gas	Other current assets	1		5		6
	Other assets	1		—		1
Power	Other current assets	15		—		15
	Total assets	$	23	$	5	$	28
Derivative liabilities not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current liabilities	$	2	$	—	$	2
	Other deferred credits and liabilities	2		—		2
Natural gas	Other current liabilities	4		16		20
	Other deferred credits and liabilities	4		13		17
Power	Other current liabilities	6		8		14
	Other deferred credits and liabilities	—		112		112
Uranium	Other current liabilities	4		—		4
	Other deferred credits and liabilities	1		—		1
	Total liabilities	$	23	$	149	$	172
2013
Derivative assets not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current assets	$	6	$	—	$	6
	Other assets	3		—		3
Natural gas	Other current assets	1		1		2
Power	Other current assets	23		—		23
	Total assets	$	33	$	1	$	34
Derivative liabilities not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current liabilities	$	2	$	—	$	2
	Other deferred credits and liabilities	1		—		1
Natural gas	Other current liabilities	5		27		32
	Other deferred credits and liabilities	6		19		25
Power	Other current liabilities	4		9		13
	Other deferred credits and liabilities	—		99		99
Uranium	Other current liabilities	5		—		5
	Other deferred credits and liabilities	1		—		1
	Total liabilities	$	24	$	154	$	178

(a) Includes derivatives subject to regulatory deferral.

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments deferred as regulatory assets or regulatory liabilities as of March 31, 2014, and December 31, 2013:

	Ameren Missouri			Ameren Illinois			Ameren
2014
Cumulative gains (losses) deferred as regulatory liabilities or assets:
Fuel oils derivative contracts(a)	$	—		$	—		$	—
Natural gas derivative contracts(b)	(6		)	(24		)	(30		)
Power derivative contracts(c)	9			(120		)	(111		)
Uranium derivative contracts(d)	(5		)	—			(5		)
2013
Cumulative gains (losses) deferred as regulatory liabilities or assets:
Fuel oils derivative contracts	$	2		$	—		$	2
Natural gas derivative contracts	(10		)	(45		)	(55		)
Power derivative contracts	19			(108		)	(89		)
Uranium derivative contracts	(6		)	—			(6		)

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(a) Represents net gains (losses) on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through December 2016 as of March 31, 2014. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014.

(b) Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2019 at Ameren and Ameren Missouri and through October 2017 at Ameren Illinois, in each case as of March 31, 2014. 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, 2014. Current losses deferred as regulatory assets include $20 million, $4 million, and $16 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2014.

(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, 2014. Current gains deferred as regulatory liabilities include $15 million and $15 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014. Current losses deferred as regulatory assets include $14 million, $6 million, and $8 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2014.

(d) Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through December 2016, as of March 31, 2014. Current losses deferred as regulatory assets include $4 million and $4 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014.

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) the 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 the 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 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, 2014, and December 31, 2013:

			Gross Amounts Not Offset in the Balance Sheet
Commodity Contracts Eligible to be Offset	Gross Amounts Recognized in the Balance Sheet		Derivative Instruments		Cash Collateral Received/Posted(a)		Net Amount
2014
Assets:
Ameren Missouri	$	23	$	9	$	—	$	14
Ameren Illinois	5		3		—		2
Ameren	$	28	$	12	$	—	$	16
Liabilities:
Ameren Missouri	$	23	$	9	$	9	$	5
Ameren Illinois	149		3		3		143
Ameren	$	172	$	12	$	12	$	148
2013
Assets:
Ameren Missouri	$	33	$	9	$	—	$	24
Ameren Illinois	1		1		—		—
Ameren	$	34	$	10	$	—	$	24
Liabilities:
Ameren Missouri	$	24	$	9	$	9	$	6
Ameren Illinois	154		1		15		138
Ameren	$	178	$	10	$	24	$	144

(a) Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current assets” and “Other assets” on the balance sheet.

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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. We calculate maximum exposures based on the gross fair value of financial instruments, including accrual and NPNS contracts. As of March 31, 2014, if counterparty groups were to fail completely to perform on contracts, Ameren, Ameren Missouri and Ameren Illinois' maximum exposure was $14 million, $9 million, and $5 million, respectively. As of December 31, 2013, if counterparty groups were to fail completely to perform on contracts, Ameren, Ameren Missouri and Ameren Illinois' maximum exposure was $13 million, $12 million, and $1 million, respectively. 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. As of March 31, 2014, the potential loss after consideration of the application of master trading and netting agreements and collateral held for Ameren, Ameren Missouri and Ameren Illinois was $5 million, $3 million, and $2 million, respectively. As of December 31, 2013, the potential loss after consideration of the application of master trading and netting agreements and collateral held for Ameren and Ameren Missouri was $6 million and $6 million, respectively.

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, 2014, and December 31, 2013, 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, 2014, or December 31, 2013, respectively, 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)
2014
Ameren Missouri	$	56	$	2	$	51
Ameren Illinois	80		3		65
Ameren	$	136	$	5	$	116
2013
Ameren Missouri	$	70	$	2	$	67
Ameren Illinois	75		15		55
Ameren	$	145	$	17	$	122

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

NOTE 7 - FAIR VALUE MEASUREMENTS

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

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

The market approach is used to measure the fair value of equity securities held in Ameren Missouri’s nuclear decommissioning trust fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants and the trustee and investment managers. The S&P 500 index comprises 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

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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 primarily 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 reasonableness review, 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 as of March 31, 2014:

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
Level 3 Derivative asset and liability - commodity contracts(a):
Ameren	Fuel oils	$	5	$	(4	)	Option model	Volatilities(%)(b)	13 - 34	16
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.25 - 0.99	0.63
	Natural gas	1		(1		)	Option model	Volatilities(%)(b)	27 - 102	40
								Nodal basis($/mmbtu)(c)	(0.3) - (0.2)	(0.2)
							Discounted cash flow	Nodal basis($/mmbtu)(c)	(0.2) - (0.1)	(0.1)
								Counterparty credit risk(%)(c)(d)	0.27 - 5	1
								Ameren Missouri credit risk(%)(c)(d)	0.43	(e)
	Power(f)	14		(124		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	27 - 57	33
								Estimated auction price for FTRs($/MW)(b)	(1,109) - 2,981	474
								Nodal basis($/MWh)(c)	(6) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	0.35	(e)
								Ameren Missouri and Ameren Illinois credit risk(%)(c)(d)	0.43	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 6	5
								Escalation rate(%)(b)(g)	2 - 3	3
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6
	Uranium	—		(5		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	34 - 40	35
Ameren Missouri	Fuel oils	$	5	$	(4	)	Option model	Volatilities(%)(b)	13 - 34	16
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.25 - 0.99	0.63
	Natural gas	1		(1		)	Option model	Volatilities(%)(b)	27 - 102	40
								Nodal basis($/mmbtu)(c)	(0.3) - (0.2)	(0.2)
							Discounted cash flow	Nodal basis($/mmbtu)(c)	(0.2) - (0.1)	(0.1)
								Counterparty credit risk(%)(c)(d)	0.27 - 5	1
								Ameren Missouri credit risk(%)(c)(d)	0.43	(e)
	Power(f)	14		(4		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	30 - 57	45
								Estimated auction price for FTRs($/MW)(b)	(1,109) - 2,981	474
								Nodal basis($/MWh)(c)	(3) - (1)	(2)
								Counterparty credit risk(%)(c)(d)	0.35	(e)
								Ameren Missouri credit risk(%)(c)(d)	0.43	(e)
	Uranium	—		(5		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	34 - 40	35
Ameren Illinois	Power(f)	$	—	$	(120	)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b)	27 - 40	32
								Nodal basis($/MWh)(b)	(6) - (1)	(3)
								Ameren Illinois credit risk(%)(c)(d)	0.43	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 6	5
								Escalation rate(%)(b)(g)	2 - 3	3
							Contract price allocation	Estimated renewable energy credit costs($/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 applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances.

(e) Not applicable.

(f) Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2018. Valuations beyond 2018 use fundamentally modeled pricing by month for peak and off-peak demand.

(g) Escalation rate applies to power prices 2026 and beyond.

27

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 as of December 31, 2013:

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
Level 3 Derivative asset and liability – commodity contracts(a):
Ameren	Fuel oils	$	8	$	(3	)	Option model	Volatilities(%)(b)	10 - 35	16
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.26 - 2	1
	Power(e)	21		(110		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	25 - 51	32
								Estimated auction price for FTRs($/MW)(b)	(1,594) - 945	305
								Nodal basis($/MWh)(c)	(3) - (1)	(2)
								Counterparty credit risk(%)(c)(d)	0.39 - 0.50	0.42
								Ameren Missouri and Ameren Illinois credit risk(%)(c)(d)	2	(f)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 5	5
								Escalation rate(%)(b)(g)	3 - 4	4
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6
	Uranium	—		(6		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	34 - 41	36
Ameren Missouri	Fuel oils	$	8	$	(3	)	Option model	Volatilities(%)(b)	10 - 35	16
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.26 - 2	1
	Power(e)	21		(2		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	25 - 51	40
								Estimated auction price for FTRs($/MW)(b)	(1,594) - 945	305
								Nodal basis($/MWh)(c)	(3) - (1)	(2)
								Counterparty credit risk(%)(c)(d)	0.39 - 0.50	0.42
								Ameren Missouri credit risk(%)(c)(d)	2	(f)
	Uranium	—		(6		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	34 - 41	36
Ameren Illinois	Power(e)	$	—	$	(108	)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b)	27 - 36	30
								Nodal basis($/MWh)(b)	(4) - 0	(2)
								Ameren Illinois credit risk(%)(c)(d)	2	(f)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 5	5
								Escalation rate(%)(b)(g)	3 - 4	4
							Contract price allocation	Estimated renewable energy credit costs($/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 applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances.

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

(f) Not applicable.

(g) Escalation rate applies to power prices 2026 and beyond.

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. No gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri or Ameren Illinois in the first three months of 2014 or 2013. At March 31, 2014, 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, 2013, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $3 million, less than $1 million, and $3 million, for Ameren, Ameren Missouri and Ameren Illinois, respectively.

28

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, 2014:

		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	$	1	$	—	$	5	$	6
	Natural gas	—		6		1		7
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	1	$	7	$	20	$	28
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	327		—		—		327
	Debt securities:
	Corporate bonds	—		61		—		61
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		94		—		94
	Asset-backed securities	—		14		—		14
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	329	$	172	$	—	$	501	(b)
	Total Ameren	$	330	$	179	$	20	$	529
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	1	$	—	$	5	$	6
	Natural gas	—		1		1		2
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	1	$	2	$	20	$	23
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	327		—		—		327
	Debt securities:
	Corporate bonds	—		61		—		61
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		94		—		94
	Asset-backed securities	—		14		—		14
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	329	$	172	$	—	$	501	(b)
	Total Ameren Missouri	$	330	$	174	$	20	$	524
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	—	$	5	$	—	$	5
Liabilities:
Ameren	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	—	$	—	$	4	$	4
	Natural gas	2		34		1		37
	Power	—		2		124		126
	Uranium	—		—		5		5
	Total Ameren	$	2	$	36	$	134	$	172
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	—	$	—	$	4	$	4
	Natural gas	2		5		1		8
	Power	—		2		4		6
	Uranium	—		—		5		5
	Total Ameren Missouri	$	2	$	7	$	14	$	23
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	29	$	—	$	29
	Power	—		—		120		120
	Total Ameren Illinois	$	—	$	29	$	120	$	149

(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.

29

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, 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	$	1	$	—	$	8	$	9
	Natural gas	—		2		—		2
	Power	—		2		21		23
	Total derivative assets - commodity contracts	$	1	$	4	$	29	$	34
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	3	$	—	$	—	$	3
	Equity securities:
	U.S. large capitalization	332		—		—		332
	Debt securities:
	Corporate bonds	—		52		—		52
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		94		—		94
	Asset-backed securities	—		10		—		10
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	335	$	159	$	—	$	494
	Total Ameren	$	336	$	163	$	29	$	528
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	1	$	—	$	8	$	9
	Natural gas	—		1		—		1
	Power	—		2		21		23
	Total derivative assets - commodity contracts	$	1	$	3	$	29	$	33
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	3	$	—	$	—	$	3
	Equity securities:
	U.S. large capitalization	332		—		—		332
	Debt securities:
	Corporate bonds	—		52		—		52
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		94		—		94
	Asset-backed securities	—		10		—		10
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	335	$	159	$	—	$	494
	Total Ameren Missouri	$	336	$	162	$	29	$	527
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	—	$	1	$	—	$	1
Liabilities:
Ameren	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	—	$	—	$	3	$	3
	Natural gas	3		54		—		57
	Power	—		2		110		112
	Uranium	—		—		6		6
	Total Ameren	$	3	$	56	$	119	$	178
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	—	$	—	$	3	$	3
	Natural gas	3		8		—		11
	Power	—		2		2		4
	Uranium	—		—		6		6
	Total Ameren Missouri	$	3	$	10	$	11	$	24
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	46	$	—	$	46
	Power	—		—		108		108
	Total Ameren Illinois	$	—	$	46	$	108	$	154

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

30

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, 2014:

		Net derivative commodity contracts
Three Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2014	$	5		$	(a)		$	5
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(2	)		(a)			(2	)
Settlements		(2	)		(a)			(2	)
Ending balance at March 31, 2014	$	1		$	(a)		$	1
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2014	$	(1	)	$	(a)		$	(1	)
Natural gas:
Beginning balance at January 1, 2014	$	—		$	—		$	—
Purchases		—			(2	)		(2	)
Settlements		—			2			2
Ending balance at March 31, 2014	$	—		$	—		$	—
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2014	$	—		$	—		$	—
Power:
Beginning balance at January 1, 2014	$	19		$	(108	)	$	(89	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(5	)		(12	)		(17	)
Settlements		(5	)		—			(5	)
Transfers out of Level 3		1			—			1
Ending balance at March 31, 2014	$	10		$	(120	)	$	(110	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2014	$	(1	)	$	(14	)	$	(15	)
Uranium:
Beginning balance at January 1, 2014	$	(6	)	$	(a)		$	(6	)
Settlements		1			(a)			1
Ending balance at March 31, 2014	$	(5	)	$	(a)		$	(5	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2014	$	—		$	(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, 2013:

		Net derivative commodity contracts
Three Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2013	$	5		$	(a)		$	5
Purchases		1			(a)			1
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
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
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	)
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.

31

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 between Level 2 and Level 3 for power derivatives were primarily caused by changes in availability of financial trades observable on electronic exchanges between the periods shown below. 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, 2014, and 2013, 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, 2014, and 2013:

	Three Months
	2014						2013
Derivative commodity contracts	Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri			Ameren Illinois		Ameren
Transfers into Level 3 / Transfers out of Level 2 - Power	$	—	$	—	$	—	$	(2	)	$	—	$	(2	)
Transfers out of Level 3 / Transfers into Level 2 - Power	1		—		1		1			—		1
Net fair value of Level 3 transfers	$	1	$	—	$	1	$	(1	)	$	—	$	(1	)

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. The Ameren Companies’ short-term borrowings 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, capital lease obligations and preferred stock at March 31, 2014, and December 31, 2013:

	March 31, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:(a)
Long-term debt and capital lease obligations (including current portion)	$	5,874	$	6,530	$	6,038	$	6,584
Preferred stock	142		119		142		118
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	3,758	$	4,200	$	3,757	$	4,124
Preferred stock	80		71		80		71
Ameren Illinois:
Long-term debt (including current portion)	$	1,692	$	1,903	$	1,856	$	2,028
Preferred stock	62		48		62		47

(a) Preferred stock is recorded in “Noncontrolling Interests” on the consolidated balance sheet.

NOTE 8 - 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 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.

Collateral Postings

Under the terms of the Illinois power procurement agreements entered into through an RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Ameren Missouri, as a winning supplier in the RFP process, may be required to post collateral to Ameren Illinois. As of March 31, 2014, and December 31, 2013, there were no collateral postings required of Ameren Missouri related to the Illinois power procurement agreements.

32

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three months ended March 31, 2014, and 2013. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K, and the money pool arrangements discussed in Note 3 - Short-term Debt and Liquidity of this report.

				Three Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2014	$	(b)	$	(a)
agreements with Ameren Illinois		2013		1		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2014		5		(b)
rent and facility services		2013		5		(b)
Total Operating Revenues		2014	$	5	$	(b)
		2013		6		(b)
Ameren Illinois power supply	Purchased Power	2014	$	(a)	$	(b)
agreements with Ameren Missouri		2013		(a)		1
Ameren Illinois transmission	Purchased Power	2014		(a)		1
services with ATXI		2013		(a)		1
Total Purchased Power		2014	$	(a)	$	1
		2013		(a)		2
Ameren Services support services	Other Operations and Maintenance	2014	$	33	$	27
agreement		2013		31		25
Insurance premiums(c)	Other Operations and Maintenance	2014		(b)		(a)
		2013		(b)		(a)
Total Other Operations and		2014	$	33	$	27
Maintenance Expenses		2013		31		25
Money pool borrowings (advances)	Interest Charges	2014	$	(b)	$	(b)
		2013		(b)		(b)

(a) Not applicable.

(b) Amount less than $1 million.

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

NOTE 9 - COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, authorities 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, Note 15 - Commitments and Contingencies and Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions, Note 10 - Callaway Energy Center and Note 12 - Divestiture Transactions and Discontinued Operations in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at March 31, 2014. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year. Both coverages were renewed in 2014.

33

Type and Source of Coverage	Maximum  Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	375		$	—
Pool participation	13,241		(a)	128		(b)
	$	13,616	(c)	$	128
Property damage:
NEIL	$	2,250	(d)	$	23	(e)
European Mutual Association for Nuclear Insurance	500		(f)	—
	$	2,750		$	23
Replacement power:
NEIL	$	490	(g)	$	9	(e)
Missouri Energy Risk Assurance Company LLC	64		(h)	—

(a) Provided through mandatory participation in an industrywide retrospective premium assessment program.

(b) Retrospective premium under the Price-Anderson Act. 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 $19 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 $128 million per incident for each licensed reactor it operates with a maximum of $19 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) NEIL provides $2.25 billion in property damage, decontamination, and premature decommissioning insurance. There is a $1.7 billion sublimit for nonradiation events, of which the last $200 million is a shared limit with other generators purchasing this coverage. The $1.7 billion sublimit for nonradiation events was not included with the April 1, 2014 renewal.

(e) All NEIL insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL.

(f) European Mutual Association for Nuclear Insurance provides $500 million in excess of the $2.25 billion property coverage provided by NEIL.

(g) Provides 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. Nonradiation events are sub-limited to $327.6 million.

(h) Provides 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 NEIL and is a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 8 - Related Party Transactions for more information on this affiliate transaction.

The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. 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 was effective September 10, 2013. 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 the Price-Anderson Act.

Losses resulting from terrorist attacks are covered under NEIL’s policies, subject to an industrywide 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, 2014, 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 $6,251 million, $4,273 million, and $1,908 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 generation, 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, discharges to water, water usage, impacts to air, land, and water, and chemical and waste handling. Complex and lengthy processes are required to obtain and renew approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures.

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The EPA is developing environmental regulations that will have a significant impact on the electric utility industry. Over time, compliance with these regulations could be particularly costly for certain companies, including Ameren Missouri, that operate coal-fired energy centers. Significant new rules proposed or promulgated include the regulation of CO₂ emissions from new energy centers; revised national ambient air quality standards for ozone, fine particulates, SO_2, and NO_x emissions; the CSAPR, which requires 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 waste water discharges from energy centers and new regulations under the Clean Water Act that could require significant capital expenditures, such as modifications to water intake structures or new cooling towers at our energy centers. The EPA is expected to propose CO₂ standards for existing fossil fuel-fired electric generation 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. 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 increased operating costs over the next five to ten years for Ameren and Ameren Missouri. Compliance with these environmental laws and regulations could be prohibitively expensive or could result in the closure or alteration of the operation of some of our energy centers. Ameren and Ameren Missouri would expect these costs to be recoverable through rates, but the nature and timing of costs, as well as the applicable regulatory framework, could result in regulatory lag.

As of March 31, 2014, Ameren and Ameren Missouri estimate capital expenditure investments of $275 million to $350 million over the next five years to comply with existing environmental regulations. This estimate assumes that CCR will continue to be regulated as nonhazardous. This estimate does not include the impacts of regulations proposed by the EPA under the Clean Water Act regarding cooling water intake structures or the impact of the proposed effluent standards applicable to steam-electric generating units, as the technology requirements of these final rules are not yet known. Considerable uncertainty remains in this estimate. The actual amount of capital expenditure investments to comply with existing environmental regulations may vary substantially from the above estimate due to uncertainty as to the precise compliance strategies that will be used and their ultimate cost, among other things.

Ameren Missouri's current environmental compliance plan for air emissions includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. Ameren Missouri has two scrubbers at its Sioux energy center, which are used to reduce SO₂ emissions and other pollutants. Currently, Ameren Missouri's compliance plan assumes the installation of additional controls including mercury control technology and electrostatic precipitator upgrades at multiple

energy centers within its coal-fired fleet during the next five years. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the CSAPR, the MATS, and other recently finalized or proposed EPA regulations. Ameren Missouri may be required to install additional pollution controls within the next six to ten years.

Environmental compliance costs at some of Ameren Missouri's energy centers could be prohibitive and additional capital investment or continued operations unwarranted. Ameren Missouri's capital expenditures and other costs are subject to MoPSC prudence reviews, which could result in cost disallowances as well as regulatory lag.

The following sections describe the more significant environmental laws and 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 2005, the EPA issued regulations with respect to SO₂ and NO_x emissions (the CAIR). In December 2008, the United States Court of Appeals for the District of Columbia Circuit found various aspects of the law to be unlawful and remanded the CAIR to the EPA for further action, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. The CSAPR regulations were vacated by the United States Court of Appeals for the District of Columbia Circuit. The EPA appealed to the United States Supreme Court. In April 2014, the United States Supreme Court reversed the decision of the United States Court of Appeals for the District of Columbia Circuit’s decision and upheld the CSAPR. Ameren and Ameren Missouri are continuing to review the United States Supreme Court’s decision and expect the EPA to issue guidance in the near future on implementing the CSAPR. Ameren Missouri has already taken actions to prepare for the implementation of the CSAPR, including the installation of two scrubbers at its Sioux energy center and burning ultra-low sulfur coal. Assuming the EPA does not revise the emission reductions previously included in the CSAPR, Ameren Missouri does not expect to make additional capital investments to comply with the CSAPR. However, Ameren Missouri will incur additional operations and maintenance costs to utilize chemicals to lower its emissions at one or more of its energy centers for compliance with the CSAPR. These higher operations and maintenance costs will be collected from customers through the FAC or higher base rates.

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 hydrogen chloride emissions. 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,

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with a case-by-case extension, by April 2016. Ameren Missouri's Labadie and Meramec energy centers requested and were granted extensions to April 2016 to comply with the MATS.

Emission Allowances

The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NO_x budget trading program, the CAIR and the CSAPR. Ameren Missouri expects to have enough allowances for 2014 to avoid making external purchases to comply with the CAIR and the acid rain program. Ameren and Ameren Missouri are continuing to review the United States Supreme Court’s decision upholding the CSAPR and will review any guidance the EPA may issue regarding implementing the CSAPR and its emission allowance program.

Greenhouse Gas Regulation

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 permit upon renewal. Currently, all Ameren energy centers have operating permits that have been modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources or new 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 to control greenhouse gas emissions. 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. In October 2013, the United States Supreme Court agreed to consider whether the Clean Air Act authorizes the EPA to regulate emissions of greenhouse gases from stationary sources, including power plants, as a result of its determination to regulate greenhouse gas emissions from motor vehicles. A ruling is expected in 2014.

In June 2013, the Obama administration announced that it had directed the EPA to set CO₂ emissions standards for both new and existing power plants. The EPA published proposed regulations in January 2014 that would set revised CO₂

emissions standards for new electricity generating units. The proposed standards would establish separate emissions limits for new natural gas-fired plants and new coal-fired plants. In addition, the Obama administration directed the EPA to propose a CO₂ emissions standard for existing power plants by June 2014 and to finalize such standard by June 2015. Currently, Ameren and Ameren Missouri are unable to predict the outcome of these rulemakings or impacts of such future regulations if and when they become effective.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases may result in significant increases in capital expenditures and operating costs, which could lead to increased liquidity needs and higher financing costs. These 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 if costs are not recovered through rates. Mandatory limits on the emission of greenhouse gases could increase costs for our customers or have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity if regulators delay or deny cost recovery in rates of these compliance costs. Ameren's and Ameren Missouri's earnings may benefit from increased investment to the extent the investments comply with greenhouse gas limitations and are reflected and recovered timely in rates.

NSR and Clean Air Litigation

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, as amended in October 2013, alleges that in performing projects at its Rush Island coal-fired energy center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the district court granted, in part, Ameren Missouri's motion to dismiss various aspects of the EPA's penalty claims. The EPA's claims for unspecified injunctive relief remain. The trial in this matter is currently scheduled to begin in 2015. Ameren Missouri believes its defenses are meritorious and will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.

Ultimate resolution of this matter could have a material adverse effect 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. The proposed rule would impose standards for reducing

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the mortality of aquatic organisms impinged on the plant's intake screens or entrained through the plant's cooling water system. All coal-fired, nuclear, and combined cycle energy centers at Ameren Missouri with cooling water systems are subject to this proposed rule. The EPA has stated that it will finalize the rule in May 2014. When finalized, the rule could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers or extensive modifications to the cooling water systems at our energy centers and if those investments are not recovered timely in rates.

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 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 the rule is enacted as proposed, Ameren Missouri would be subject to the revised limitations beginning as early as July 1, 2017, but no later than July 1, 2022, however, the final rule will determine the schedule. The EPA expects to issue final guidelines by September 30, 2015.

Ash Management

In May 2010, the EPA announced proposed new regulations regarding 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. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric generating units would apply to ash ponds and CCR management and that it intended to align this proposal with the CCR rules when finalized. The EPA is expected to issue regulations describing how it will regulate CCR by December 2014. Ameren Missouri is 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 Missouri is 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.

Remediation

We are involved in a number of remediation actions to clean up sites impacted by hazardous substances 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 at several contaminated sites.

As of March 31, 2014, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois. These sites 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 incurred. Costs are subject to annual review by the ICC.

As of March 31, 2014, 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.

The following table presents, as of March 31, 2014, the estimated obligation to complete the remediation of these former MGP sites:

	Estimate				Recorded   Liability(a)
	Low		High
Ameren	$	269	$	345	$	269
Ameren Missouri	3		4		3
Ameren Illinois	266		341		266

(a) Recorded liability represents the estimated minimum probable obligations, as no other amount within the range was 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 used an off-site landfill, which Ameren Illinois did not own, in connection with the former operation of an energy center. Ameren Illinois could be required to perform certain maintenance activities associated with that landfill. As of March 31, 2014, 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 some underground storage tanks and a water treatment plant in Illinois. As of March 31, 2014, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.

Ameren Missouri is investigating and addressing 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

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Company or its predecessor and successor companies. While Ameren Missouri is the current owner of the site, it did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other potentially responsible parties, are performing a site investigation. As of March 31, 2014, 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 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 investigation and 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 therefore, Ameren Missouri believes it has no liability at March 31, 2014, 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 potentially responsible parties to evaluate the extent of potential contamination with respect to Sauget Area 2.

In December 2013, the EPA issued its record of decision for Sauget Area 2 approving the investigation and the remediation alternatives recommended by the potentially responsible parties. Further negotiation among the potentially responsible parties will determine how to fund the implementation of the EPA approved cleanup remedies. As of March 31, 2014, Ameren Missouri estimated its obligation related to Sauget Area 2 at $1 million to $2.5 million. During the first quarter of 2014, Ameren Missouri recorded an additional liability of $0.7 million, to reflect the negotiations with the potentially responsible parties, for a total liability of $1 million to represent its estimated minimum obligation.

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, 2014, Ameren Missouri estimated the obligation related to the cleanup at $1.6 million to $4.5 million. Ameren Missouri recorded a liability of $1.6 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.

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, 2014, Ameren Missouri had an insurance receivable balance of $68 million.

In June 2010, Ameren Missouri sued an insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed that the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In January 2011, the district court ruled that the parties must first pursue alternative dispute resolution and enforced the forum selection clause of their coverage agreement. The forum selection clause requires use of New York law and effectively requires mandatory arbitration. 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 public policy voids the forum selection clause. In September 2013, the district court ruled that Missouri public policy voids the forum selection clause.

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, which is pending in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. The insurance company filed a motion to compel arbitration, which the district court denied. In April 2013, the United States Court of Appeals for the Eighth Circuit affirmed the district court’s denial of the insurer’s motion and remanded the case to the district court.

Ameren's and Ameren Missouri's results of operations, financial position and liquidity could be adversely affected if Ameren Missouri's remaining liability insurance claims are not paid by insurers.

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 at our present or former energy centers. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies, with

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the average number of parties being 85 as of March 31, 2014. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.

The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of March 31, 2014:

Ameren	Ameren Missouri	Ameren Illinois	Total(a)
1	47	56	71

(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, 2014, Ameren, Ameren Missouri and Ameren Illinois had liabilities of $12 million, $5 million, and $7 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 IP 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, 2014, 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. The rider will permit recovery 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 2,400 accounts, primarily in annexed areas, for the period 2004 through 2012. In July 2013, the O’Fallon city administrator issued an order stating that Ameren Illinois was liable to the city of O’Fallon for $4 million. In August 2013, Ameren Illinois filed an appeal and a stay of the O’Fallon city administrator’s order to the Circuit Court of St. Clair County. In addition, in December 2012, the city of Peoria issued a tax liability notice alleging that Ameren Illinois failed to collect prior-period municipal taxes from certain accounts. In September 2013, a hearing officer issued an order stating that Ameren Illinois was liable to the city of Peoria for $0.5 million. Ameren Illinois filed an appeal and a stay of the order to the Circuit Court of Peoria County. Ameren Illinois believes its defenses to the allegations are meritorious. As of March 31, 2014, Ameren Illinois estimated its obligation at $1 million to $5 million. Ameren Illinois recorded a liability of $1 million, which reflects potential settlements with both of the cities.

In addition, at the end of 2012, five other cities issued tax liability notices alleging that Ameren Illinois failed to collect an immaterial amount of taxes from certain accounts.

NOTE 10 - CALLAWAY ENERGY CENTER

Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. Under the NWPA, Ameren and other utilities that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established the fee that these utilities pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each 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 Missouri and other utilities have entered into standard contracts with the federal government. The government, represented by the DOE, is responsible for implementing these provisions of the NWPA. Consistent with the NWPA and its 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.

Although both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, the federal government is not meeting its disposal obligation. Ameren Missouri has sufficient installed capacity at the Callaway energy center to store its spent nuclear fuel generated through 2020, and it has the capability for additional storage capacity for spent nuclear fuel generated through the end of the energy center’s current license. 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 operations of the energy center.

In January 2009, the federal government announced that a spent nuclear fuel repository at Yucca Mountain, Nevada was unworkable. The federal government took steps to terminate the Yucca Mountain program, while acknowledging its continuing obligation to dispose of utilities’ spent nuclear fuel. In January 2013, the DOE issued its plan for the management and disposal of spent nuclear fuel. 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, co-located with the pilot facility. The plan also proposes to site a permanent geological repository by 2026, to characterize the site and to design and to license the repository by 2042, and to begin operation by 2048.

In view of the federal government's efforts to terminate the Yucca Mountain program, the Nuclear Energy Institute, a number of individual utilities, and the National Association of Regulatory Utility Commissioners sued the DOE in the United States Court of Appeals for the District of Columbia Circuit, seeking the suspension of the one mill nuclear waste fee, alleging that the DOE failed to undertake an appropriate fee adequacy review reflecting the current unsettled state of the nuclear waste program. In a June 2012 decision, the court ruled that the DOE's fee adequacy review was legally inadequate and remanded the

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matter to the DOE. Although the court ruled it has the power to direct the DOE to suspend the fee, the court decided that it was premature to do so. Instead, the court ordered the DOE to provide within six months a revised assessment of the amount that should be collected. In January 2013, the DOE issued the revised assessment required by the court. The DOE determined that “neither insufficient nor excess revenues are being collected,” and it proposed no adjustment to the one mill nuclear waste fee. In November 2013, the court rejected the DOE's revised assessment and ordered the DOE to submit a proposal to the United States Congress to reduce the fee to zero. In January 2014, the DOE submitted a proposal to the United States Congress to reduce the fee to zero. Absent further action by the DOE, the fee reduction is expected to take effect during the second quarter of 2014. The nuclear waste fee is included in Ameren Missouri’s FAC. Therefore, if the fee is reduced to zero, the cost reduction will be passed on to electric utility customers with no material effect on Ameren’s and Ameren Missouri’s net income.

As a result of the DOE's failure to begin to dispose of spent nuclear fuel from commercial nuclear energy centers and fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners have also 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. It sought reimbursement for 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 the DOE performed its contractual obligations. In June 2011, the parties entered into a settlement agreement that provides for annual recovery of additional spent fuel storage and related costs incurred from 2010 through 2013 with the ability to extend the recovery period as mutually agreed to by the parties. The parties have agreed in principle to extend the recovery period through 2016. In March 2014, Ameren Missouri submitted its 2013 costs to the DOE for reimbursement under the settlement agreement. Ameren Missouri expects to receive the 2013 cost reimbursement of approximately $15 million during the third quarter of 2014. This reimbursement is included in "Miscellaneous accounts and notes receivable" on Ameren’s and Ameren Missouri’s March 31, 2014 and December 31, 2013 balance sheets. Included in these reimbursements are costs related to a dry spent fuel storage facility Ameren Missouri is constructing at its Callaway energy center. Ameren Missouri intends to begin transferring spent fuel assemblies to this facility in 2015. Until the facility is completed, Ameren Missouri will apply for reimbursement from the DOE for the cost to construct the dry spent fuel storage facility along with related allowable costs.

In December 2011, Ameren Missouri submitted a license extension application to 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 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.

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. Amounts collected from customers are deposited into the external nuclear decommissioning trust fund to provide for the Callaway energy center’s decommissioning. 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 2013, 2012, and 2011. 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. The last cost study and funding analysis were filed with the MoPSC in September 2011. In October 2012, the MoPSC issued an order approving the stipulation and agreement between Ameren Missouri and the MoPSC staff that maintained the current rate of deposits to the trust fund and the rate of return assumptions used in the analysis. 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 the next triennial cost study and funding analysis is approved by the MoPSC. 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 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.

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

NOTE 11 - 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, 2014, the plan’s estimated investment performance through March 31, 2014, and Ameren’s pension funding policy, Ameren expects to make annual contributions of $20 million to $100 million in each of the next five years, with aggregate estimated contributions of $270 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 employees’ beneficiary association 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, 2014, and 2013:

	Pension Benefits						Postretirement Benefits
	Three Months						Three Months
	2014			2013			2014			2013
Service cost	$	21		$	24		$	5		$	6
Interest cost	49			40			13			12
Expected return on plan assets	(57		)	(54		)	(16		)	(16		)
Amortization of:
Prior service cost (benefit)	—			(1		)	(1		)	(1		)
Actuarial loss	12			22			(1		)	2
Net periodic benefit cost	$	25		$	31		$	—		$	3

Ameren Missouri and Ameren Illinois are responsible for their respective shares of Ameren’s pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three months ended March 31, 2014, and 2013:

	Pension Costs				Postretirement Costs
	Three Months					Three Months
	2014		2013			2014			2013
Ameren Missouri	$	17	$	18		$	1		$	2
Ameren Illinois	8		10			(1		)	1
Other	—		3			—			—
Ameren(a)	$	25	$	31		$	—		$	3

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

NOTE 12 - DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS

On December 2, 2013, Ameren completed the divestiture of New AER to IPH, in accordance with the transaction agreement between Ameren and IPH dated March 14, 2013, as amended by a letter agreement dated December 2, 2013. The transaction agreement with IPH provides that if the Elgin, Gibson City, and Grand Tower gas-fired energy centers are subsequently sold to a third party and Medina Valley receives proceeds within two years of the closing of the New AER divestiture, 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, which totaled $137.5 million.

On January 31, 2014, Medina Valley completed the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers

to Rockland Capital for a total purchase price of $168 million, before consideration of a net working capital adjustment. The agreement with Rockland Capital required $17 million of the purchase price to be held in escrow until the two-year anniversary of the closing of the sale to fund certain indemnity obligations, if any, of Medina Valley. The Rockland Capital escrow receivable balance is reflected on Ameren's March 31, 2014 consolidated balance sheet in "Other assets." The corresponding payable due to Genco is reflected on Ameren's March 31, 2014 consolidated balance sheet in "Other deferred credits and liabilities." An immaterial net working capital adjustment with Rockland Capital is expected to be finalized during the second quarter of 2014. Medina Valley expects to pay Genco any remaining portion of the escrow balance on January 31, 2016. Ameren did not record a gain from its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers.

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Discontinued Operations Presentation

New AER and the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers have been classified collectively in Ameren’s consolidated financial statements as discontinued operations for all periods presented in this report. The disposal groups have been aggregated in the disclosures below. See Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information related to disposal groups. The following table presents the components of discontinued operations in Ameren's consolidated statement of income (loss) for the three months ended March 31, 2014, and 2013:

	Three months
	2014			2013
Operating revenues	$	1		$	264
Operating expenses	(2		)	(415		)	(a)
Operating loss	(1		)	(151		)
Other loss	—			(2		)
Interest charges	—			(11		)
Loss before income taxes	(1		)	(164		)
Income tax expense	—			(35		)
Loss from discontinued operations, net of taxes	$	(1	)	$	(199	)

(a) Included a noncash pretax asset 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.

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. Also during the three months ended March 31, 2013, Ameren adjusted the accumulated deferred income taxes on its consolidated balance sheet to reflect the excess of tax basis over financial reporting basis of its stock investment in AER, when it became apparent 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 then-expected tax benefits of $63 million related to the pretax loss from discontinued operations including the impairment charge, during the three months ended March 31, 2013.

During the three months ended March 31, 2014, Ameren recorded adjustments for its estimate of the New AER net working capital adjustment and for certain contingent liabilities associated with the New AER divestiture to IPH. Ameren also

recognized the operating revenues and operating expenses associated with the Elgin, Gibson City, and Grand Tower energy centers prior to the completion of their sale to Rockland Capital on January 31, 2014. The operating expenses associated with the abandoned Meredosia and Hutsonville energy centers were also included in discontinued operations. The aggregate result of these items was a $1 million loss from discontinued operations during the three months ended March 31, 2014.

Ameren and IPH are in the process of finalizing the net working capital adjustment. Additionally, the final tax basis of the AER disposal group and the related tax benefit resulting from the transaction agreement, as amended, with IPH are dependent upon 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 ultimately realized in discontinued operations may differ materially from those recorded as of March 31, 2014.

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, 2014, and December 31, 2013:

	March 31, 2014		December 31, 2013
Assets of discontinued operations
Cash and cash equivalents	$	—	$	—
Accounts receivable and unbilled revenue	—		5
Materials and supplies	—		5
Property and plant, net	—		142
Accumulated deferred income taxes, net(a)	15		13
Total assets of discontinued operations	$	15	$	165
Liabilities of discontinued operations
Accounts payable and other current obligations	$	2	$	5
Asset retirement obligations(b)	31		40
Total liabilities of discontinued operations	$	33	$	45

(a) Balances primarily consist of deferred income tax assets related to the abandoned Meredosia and Hutsonville energy centers.

(b) Includes AROs associated with the abandoned Meredosia and Hutsonville energy centers of $31 million at March 31, 2014, and December 31, 2013.

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Pursuant to the IPH transaction agreement, as amended, Ameren is obligated to pay up to $34 million for certain contingent liabilities. Of these liabilities, $29 million were included in "Other deferred credits and liabilities" and $5 million were included in "Accounts and wages payable" on Ameren's March 31, 2014 consolidated balance sheet.

The note receivable from Marketing Company related to the cash collateral support provided to New AER was $27 million and $18 million at March 31, 2014, and December 31, 2013, respectively, and was reflected on Ameren's consolidated balance sheet in "Other assets." This receivable to Ameren is due, with interest, on December 2, 2015, or sooner as cash collateral requirements are reduced. This cash collateral support is part of Ameren’s obligation to provide credit support to New AER until December 2, 2015, as discussed below.

Ameren Guarantees and Letters of Credit

The transaction agreement, as amended, requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the December 2, 2013, closing date of the divestiture. Ameren must also provide such additional credit support as required by contracts entered into prior to the closing date, in each case until December 2, 2015. IPH shall indemnify Ameren for any payments Ameren makes pursuant to these credit support obligations if the counterparty does not return the posted collateral to Ameren. IPH's indemnification obligation is 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 until December 2, 2015.

At March 31, 2014, Ameren had a total of $184 million in guarantees outstanding for New AER, which included:

• $171 million related to guarantees supporting Marketing Company for physically and financially settled power transactions with its counterparties that were in place at the December 2, 2013 closing of the divestiture, as well as for Marketing Company's clearing broker and other service agreements. If Marketing Company did not fulfill its obligations to these counterparties who had active open positions as of March 31, 2014, Ameren would have been required under its guarantees to provide $17 million to the counterparties.

• $13 million related to requirements for leasing agreements and potential environmental obligations.

Additionally, at March 31, 2014, Ameren had issued letters of credit totaling $9 million as credit support on behalf of New AER.

Ameren has not recorded a reserve for these contingent obligations because it does not believe a payment with respect to any of these guarantees was probable as of March 31, 2014.

NOTE 13 - SEGMENT INFORMATION

Ameren has two reportable segments: Ameren Missouri and Ameren Illinois. The Ameren Missouri segment for both Ameren and Ameren Missouri includes all of 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 category called Other primarily includes Ameren parent company activities, Ameren Services, and ATXI. In 2013, the Other category also included certain corporate activities previously included in the Merchant Generation segment.

The following table presents information about the reported revenues and specified items reflected in Ameren’s net income attributable to Ameren Corporation from continuing operations for the three months ended March 31, 2014, and 2013, and total assets in continuing operations as of March 31, 2014, and December 31, 2013.

Three Months	Ameren Missouri		Ameren Illinois		Other			Intersegment Eliminations			Ameren
2014
External revenues	$	811	$	774	$	9		$	—		$	1,594
Intersegment revenues	6		—		1			(7		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	47		53		(3		)	—			97
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
As of March 31, 2014:
Total assets	$	12,948	$	7,640	$	898		$	(335	)	$	21,151	(a)
As of December 31, 2013:
Total assets	$	12,904	$	7,454	$	752		$	(233	)	$	20,877	(a)

(a)    Excludes total assets from discontinued operations of $15 million and $165 million as of March 31, 2014, and December 31, 2013, respectively.

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

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

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. 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.

• Union Electric Company, doing business as 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, doing business as Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

Ameren has various other subsidiaries responsible for activities such as the provision of shared services. Ameren also has a subsidiary, ATXI, that operates a FERC rate-regulated electric transmission business and is developing the Illinois Rivers project.

The operating results, assets, and liabilities for New AER and the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers have been presented separately as discontinued operations for all periods presented in this report. Unless otherwise stated, the following sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations exclude discontinued operations for all periods presented. On January 31, 2014, Medina Valley completed its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. See Note 12 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for additional information regarding the discontinued operations presentation. See Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information regarding Ameren’s divestiture of New AER in December 2013.

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. Ameren Missouri and Ameren Illinois have no subsidiaries, and therefore their financial statements are not prepared on a consolidated basis. All tabular dollar amounts are in millions, unless otherwise indicated.

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

OVERVIEW

Net income attributable to Ameren Corporation was $96 million in the first quarter of 2014, compared with a net loss of $145 million in the first quarter of 2013. Net income attributable to Ameren Corporation from continuing operations was $97 million in the first quarter of 2014, compared with net income of $54 million in the first quarter of 2013. Net income from continuing operations was favorably affected by colder winter temperatures that drove higher electric and natural gas sales volumes. In addition, earnings increased because of increased rates for Ameren Illinois and ATXI transmission service under formula ratemaking, reflecting additional infrastructure investment; increased Ameren Illinois electric delivery service earnings under formula ratemaking, reflecting additional infrastructure investment and a higher allowed return on equity, and higher rates for Ameren Illinois natural gas distribution service pursuant to a December 2013 ICC order, each effective in January 2014. There was also a substantial elimination of costs previously incurred in support of the divested merchant generation business that benefited 2014 earnings comparisons. Additionally, net income from continuing operations was favorably affected by decreased interest expense.

Ameren will continue to execute on its strategy of investing and operating its utilities in a manner consistent with existing regulatory frameworks, as well as working to enhance those frameworks and advocating for responsible energy policies. Ameren is focused on creating and capitalizing on opportunities to invest in its rate-regulated businesses for the benefit of its customers and shareholders. Consistent with previous plans, Ameren will continue to allocate less discretionary capital to Ameren Missouri and greater levels of discretionary capital to Ameren Illinois energy delivery service and Ameren Illinois and ATXI electric transmission service projects because these services operate under formulaic regulatory frameworks that are more supportive of infrastructure investment. As a key component of Ameren’s long-term strategy to enhance regulatory frameworks and advocate for responsible energy policies, Ameren Missouri will continue to actively work with legislators and other key stakeholders to build support for energy policies that reduce regulatory lag and support investment in aging

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energy infrastructure that will result in long-term benefits for its customers.

Ameren Missouri will file for increased electric service rates by July 15, 2014. The rate request will seek an increase to recover increased operating costs, including higher net fuel costs; to recover and earn a return on additional electric infrastructure investments made for the benefit of its customers; and to reflect rebates provided for customer-installed solar generation. The additional infrastructure investments include several significant projects. These projects include the replacement of the nuclear reactor head at Ameren Missouri's Callaway energy center in order to ensure continued safe and dependable operations; upgrades to the electrostatic precipitators at Ameren Missouri's coal-fired Labadie energy center to meet more stringent environmental regulations and reduce air emissions; and two new substations in St. Louis. Additionally, Ameren Missouri has begun construction on the O’Fallon energy center, Missouri’s largest investor-owned utility solar power facility. These projects are scheduled for completion by the fourth quarter of 2014 and would be included in rate base as a part of Ameren Missouri’s July 2014 rate case filing. In February 2014, Ameren Missouri’s largest customer, Noranda, and 37 residential customers filed earnings complaint and rate shift complaint cases with the MoPSC. Ameren Missouri does not believe that a reduction in electric service rates is justified and will file testimony that supports that position, which is consistent with Ameren Missouri’s expected July 2014 rate case filing. The rate shift complaint case seeks to reduce Noranda’s electricity cost with an offsetting increase in electricity cost for Ameren Missouri’s other customers. While the rate shift proposal is revenue neutral to Ameren Missouri, Ameren Missouri does not believe that the proposed reduction to Noranda’s electric rates, which are significantly below Ameren Missouri’s cost of service, is appropriate or in the best interests of Ameren Missouri’s other electric customers.

In April 2014, the United States Supreme Court upheld the CSAPR. Ameren Missouri is continuing to review the United States Supreme Court’s decision and expects the EPA to issue guidance in the near future on implementing the CSAPR. Ameren Missouri has already taken actions to prepare for the implementation of the CSAPR, including the installation of two scrubbers at its Sioux energy center and burning ultra-low sulfur coal. Assuming the EPA does not revise the emission reductions previously included in the CSAPR, Ameren Missouri does not expect to make additional capital investments to comply with the CSAPR.

In April 2014, Ameren Illinois filed with the ICC its annual electric delivery service formula rate update to establish the revenue requirement used to set rates for 2015. Pending ICC approval, Ameren Illinois’ update filing will result in a $206 million increase in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2015. An ICC decision on this April 2014 filing is expected by December 2014. These rates will affect Ameren Illinois' cash flows during 2015.

Under the IEIMA, Ameren Illinois is subject to performance standards, including improvements in service reliability to reduce

both the frequency and duration of outages. Ameren Illinois continues to make investments to improve electric delivery service reliability and plans to invest in smart grid infrastructure, including smart meters, which enables customers to better manage their energy costs. The implementation of advanced technology is increasing electric system performance throughout Ameren Illinois’ service territory, and over time, will improve service reliability by helping Ameren Illinois detect and isolate outages faster. Ameren Illinois is on track to meet the performance goals and the incremental capital investment required by the IEIMA, as well as pass the IEIMA rate impact test for the two-year period ending May 31, 2014. The investments made in modernizing the system are also generating new jobs.

Over the 2014 through 2018 period, Ameren currently plans to invest $2.25 billion in FERC-regulated electric transmission projects because of the local and regional needs for transmission investment and FERC’s constructive forward-looking formula ratemaking framework (ATXI - $1.4 billion; Ameren Illinois - $850 million). ATXI’s Illinois Rivers project, estimated at a total cost of $1.1 billion, is in the early stages of construction. ATXI is currently reviewing, and expects during 2014 to update, the estimated cost of the Illinois Rivers project incorporating the final route approved by the ICC, which is longer than originally proposed. ATXI plans to request a certificate of public convenience and necessity from the ICC for the Spoon River project in the third quarter of 2014. An ICC decision on this filing is expected in 2015. Separate from the ATXI projects discussed above, Ameren Illinois expects to invest approximately $850 million in electric transmission assets through 2018 to address load growth and reliability requirements.

In November 2013, a customer group filed a complaint case with FERC seeking a reduction in the allowed return on common equity to 9.15%, as well as a limit on the common equity ratio, under the MISO tariff. Currently, the FERC-allowed return on common equity for MISO transmission owners is 12.38%. This complaint case could result in a reduction to Ameren Illinois' and ATXI's allowed return on common equity. That reduction could also result in a refund for transmission service revenues earned after the filing of the complaint case in November 2013. FERC has not issued an order in this case, and it is under no deadline to do so. Ameren and Ameren Illinois continue to be actively engaged in this proceeding and strongly believe that constructive ratemaking policies, including the allowed return on common equity level, play a pivotal role in incenting investment, as evidenced by their current investment plans.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Weather, economic conditions, the effects of energy efficiency programs, and the actions of key customers 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 prices we charge for our services. We principally use coal, nuclear fuel, natural gas, methane gas, and oil for fuel in our operations. The prices for

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these commodities can fluctuate significantly because of the global economic and political environment, weather, supply and demand, and many other factors. We have natural gas cost recovery mechanisms for our Illinois and Missouri natural gas delivery service businesses, a purchased power cost recovery mechanism for our Illinois electric delivery service business, and a FAC for our Missouri electric utility business. Ameren Illinois' electric delivery service utility business, pursuant to the IEIMA, conducts an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for that year, with recoveries from or refunds to customers made in a subsequent year. Included in Ameren Illinois' revenue requirement reconciliation is a formula for the return on equity, which is equal to the average of the monthly 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 following table presents a summary of Ameren's earnings for the three months ended March 31, 2014, and 2013:

	Three Months Ended March 31,
	2014		2013
Net income (loss) attributable to Ameren Corporation	$	96	$	(145	)
Earnings (loss) per common share - basic	0.40		(0.60		)
Net income attributable to Ameren Corporation - continuing operations	97		54
Earnings per common share - basic - continuing operations	0.40		0.22

Net income attributable to Ameren Corporation from continuing operations increased $43 million, or 18 cents per

share, in the first quarter of 2014 compared to the first quarter of 2013. The increase in net income attributable to Ameren Corporation from continuing operations between periods was caused by increased net income in the Ameren Missouri segment of $7 million, increased net income in the Ameren Illinois segment of $22 million, and decreased net loss in other nonregistrant subsidiaries of $14 million.

Net income from continuing operations at Ameren was favorably affected in the first quarter of 2014, compared with the same period in 2013, by:

• the effect of colder winter temperatures on electric and natural gas demand (estimated at 7 cents per share);

• higher electric transmission rates at Ameren Illinois and ATXI because of additional rate base (3 cents per share);

• the substantial elimination of costs previously incurred in support of the divested merchant generation business (3 cents per share);

• decreased interest expense, primarily due to interest associated with pre-MEEIA energy efficiency programs as well as Ameren Missouri’s October 2013 long-term debt retirement and redemption (3 cents per share); and

• an increase in Ameren Illinois’ electric delivery service earnings under formula ratemaking due to increased rate base and a higher allowed return on equity as a result of increased yields on the 30-year United States Treasury bonds (estimated 2 cents per share).

The cents per share information presented above is based on the average shares outstanding in the first quarter of 2013. There were no material differences between the basic and diluted average shares outstanding for either the first quarter of 2014 or 2013.

For additional details regarding the Ameren Companies’ results of operations, 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 Income (Loss) from Discontinued Operations, Net of Taxes, 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, 2014, and 2013:

	Ameren Missouri			Ameren Illinois			Other / Intersegment Eliminations			Ameren
Three Months 2014:
Electric margins	$	512		$	272		$	6		$	790
Natural gas margins	28			157			(1		)	184
Other operations and maintenance	(227		)	(200		)	7			(420		)
Depreciation and amortization	(116		)	(63		)	(2		)	(181		)
Taxes other than income taxes	(78		)	(46		)	(3		)	(127		)
Other income (expenses)	10			(1		)	—			9
Interest charges	(52		)	(30		)	(10		)	(92		)
Income taxes	(29		)	(35		)	—			(64		)
Income (loss) from continuing operations	48			54			(3		)	99
Loss from discontinued operations, net of tax	—			—			(1		)	(1		)
Net income (loss)	48			54			(4		)	98
Preferred dividends	(1		)	(1		)	—			(2		)
Net income (loss) attributable to Ameren Corporation	$	47		$	53		$	(4	)	$	96
Three Months 2013:
Electric margins	$	493		$	233		$	(2	)	$	724
Natural gas margins	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 (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 interests and preferred dividends	(1		)	(1		)	—			(2		)
Net income (loss) attributable to Ameren Corporation	$	40		$	31		$	(216	)	$	(145	)

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Margins

The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in the three months ended March 31, 2014, compared with the same period in 2013. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as gas revenues less gas purchased for resale. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP and may not be comparable to other companies' presentations or more useful than the GAAP information we provide elsewhere in this report.

Three Months	Ameren Missouri			Ameren Illinois			Other(a)		Ameren
Electric revenue change:
Effect of weather (estimate)(b)	$	26		$	4		$	—	$	30
Base rates (estimate)	—			22			—		22
Recovery of FAC under-recovery(c)	(4		)	—			—		(4		)
Off-system sales and transmission services revenues (included in base rates)	(7		)	—			1		(6		)
MEEIA (energy efficiency)	11			—			—		11
Transmission services	—			6			7		13
Bad debt, energy efficiency programs and environmental remediation cost riders	—			6			—		6
Illinois pass-through power supply costs	—			(46		)	—		(46		)
Sales volume (excluding the estimated effect of abnormal weather)	(6		)	3			—		(3		)
Other	(3		)	(2		)	—		(5		)
Total electric revenue change	$	17		$	(7	)	$	8	$	18
Fuel and purchased power change:
Energy costs included in base rates	$	(2	)	$	—		$	—	$	(2	)
Recovery of FAC under-recovery(c)	4			—			—		4
Illinois pass-through power supply costs	—			46			—		46
Total fuel and purchased power change	$	2		$	46		$	—	$	48
Net change in electric margins	$	19		$	39		$	8	$	66
Natural gas margins change:
Effect of weather (estimate)(b)	$	1		$	6		$	—	$	7
Base rates (estimate)	—			10			—		10
Gross receipts tax	—			4			—		4
Bad debt, energy efficiency programs and environmental remediation cost riders	—			3			—		3
Sales volume (excluding the estimated effect of abnormal weather) and other	—			3			—		3
Net change in natural gas margins	$	1		$	26		$	—	$	27

(a) Primarily includes amounts for ATXI and intercompany eliminations.

(b) Represents the estimated margin impact resulting primarily from the effects of changes in cooling and heating degree-days on electric and natural gas demand compared with the prior-year period; this is 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 $66 million, or 9%, for the three months ended March 31, 2014, compared with the same period in 2013. Ameren's natural gas margins increased by $27 million, or 17%, for the three months ended March 31, 2014, compared with the same period in 2013. These results were primarily driven by Ameren Missouri and Ameren Illinois results, as discussed below. Ameren's electric margins also reflected the results of operations of ATXI. ATXI’s transmission revenues increased by $7 million, for the three months ended March 31, 2014, compared with the same period in 2013, under forward-looking formula ratemaking reflecting increased rate base investment and recoverable costs.

Ameren Missouri

Ameren Missouri has a FAC cost recovery mechanism that allows Ameren Missouri to recover, through customer rates, 95% of changes in net energy costs greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudence reviews. Net energy cost includes fuel (coal, coal transportation, natural gas for generation, and enriched uranium), certain fuel additives, emission allowances, purchased power costs, transmission costs and revenues, and MISO costs and revenues, net of off-system sales revenues. Ameren Missouri accrues, as a regulatory asset, net energy costs that exceed the amount set in base rates (FAC under-recovery). Net recovery of these costs under the FAC through customer rates decreased$4 million, for the three months ended March 31, 2014, compared

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with the same period in 2013, with a corresponding offset to fuel expense to reduce the previously recognized FAC regulatory asset.

Ameren Missouri's electric margins increased by $19 million, or 4%, for the three months ended March 31, 2014, compared with the same period in 2013. The following items had a favorable effect on Ameren Missouri's electric margins:

• Winter temperatures in 2014 were colder-than-normal compared to normal temperatures in 2013, as heating degree-days increased 17%, which increased revenues by an estimated $26 million, partially offset by an increase in net energy costs of $9 million. The increase in net energy costs is the sum of the change in energy costs included in base rates ($2 million) and the change in off-system sales and transmission services revenues ($7 million) in the above table.

• Higher revenues associated with the MEEIA energy efficiency program cost recovery mechanism ($4 million) and lost revenue recovery mechanism ($7 million), which increased revenues by a combined $11 million. The higher revenues were driven by greater customer participation in the second year of the MEEIA program, which led to higher recovery of lost revenues. The lost revenue recovery mechanism helps compensate Ameren Missouri for lower sales from energy efficiency-related volume reductions in current and future periods. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency program costs.

Ameren Missouri's electric margins were unfavorably affected by lower sales volumes. Excluding the estimated effect of abnormal weather, total retail sales volumes decreased 1% primarily caused by the MEEIA program, which decreased revenues by an estimated $6 million.

Ameren Missouri's natural gas margins increased by $1 million, or 4%, for the three months ended March 31, 2014, compared with the same period in 2013. Ameren Missouri's natural gas margins were favorably affected by winter temperatures in 2014 that were colder-than-normal compared to normal temperatures in 2013, as heating degree-days increased 17%, which increased revenues by an estimated $1 million.

Ameren Illinois

Ameren Illinois’ electric revenues decreased by $7 million; however, electric revenues would have increased by $39 million except for a $46 million decline in revenues collected from customers for purchased power that were offset by a corresponding decrease in pass-through power supply costs. These pass-through power supply costs do not affect margins because all power purchased on behalf of Ameren Illinois customers is recovered through a cost recovery mechanism. Revenues decreased because of lower power prices on power purchases and reduced volumes caused by customers who switched to alternative retail electric suppliers, which increased significantly in 2013.

Ameren Illinois participates in the performance-based formula ratemaking framework pursuant to the IEIMA. The IEIMA provides for an annual reconciliation of Ameren Illinois' electric delivery service revenue requirement. As of each balance sheet date, Ameren Illinois records its estimate of the electric delivery service revenue effect resulting from the reconciliation of the revenue requirement necessary to reflect the actual recoverable costs incurred for that year with the revenue requirement that was in effect for that year. See Operations and Maintenance Expenses in this section for further information regarding the revenue requirement. If the current year's revenue requirement is greater than the revenue requirement customer rates were based upon, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional costs from customers within the next two years. If the current year's revenue requirement is less than the revenue requirement customer rates were based upon, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within the next two years. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding Ameren Illinois' revenue requirement reconciliation pursuant to the IEIMA.

Ameren Illinois' electric margins increased by $39 million, or 17%, for the three months ended March 31, 2014, compared with the same period in 2013. The following items had a favorable effect on Ameren Illinois' electric margins:

• Electric delivery service formula ratemaking adjustments resulting from the reconciliation of the revenue requirement pursuant to the IEIMA, which increased revenues by an estimated $22 million. The adjustments were primarily caused by increased rate base, a higher allowed return on equity due to a rise in 30-year United States Treasury bond yields, and higher recoverable costs.

• Transmission revenues increased by $6 million under forward-looking formula ratemaking because of higher rate base investment and recoverable costs.

• A net increase in recovery of bad debt expenses, energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms, which increased revenues by $6 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.

• Winter temperatures in 2014 were colder-than-normal compared to normal temperatures in 2013, as heating degree-days increased 19%, which increased revenues by an estimated $4 million.

• Excluding the estimated effect of abnormal weather, total retail sales volumes increased 1% largely due to higher residential and commercial sales driven, in part, by additional customers, which increased revenues by $3 million.

Ameren Illinois' natural gas margins increased by $26 million or 20%, for the three months ended March 31, 2014, compared with the same period in 2013. The following items had a favorable effect on Ameren Illinois' natural gas margins:

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• Higher natural gas rates effective January 2014, which increased revenues by an estimated $10 million.

• Winter temperatures in 2014 were colder-than-normal compared to normal temperatures in 2013, as heating degree-days increased 19%, which increased revenues by an estimated $6 million.

• Increased gross receipts taxes due primarily to higher natural gas rates and higher sales as a result of colder winter temperatures in 2014 compared with 2013, 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.

• A 19% increase in natural gas transportation sales primarily driven by the colder-than-normal temperatures, which increased margins by $3 million.

• A net increase in recovery of bad debt expenses, energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms which increased revenues by $3 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.

Other Operations and Maintenance Expenses

Ameren Corporation

Other operations and maintenance expenses were $21 million higher in the first quarter of 2014, as compared with the first quarter of 2013, primarily due to increased expenses at Ameren Missouri and Ameren Illinois as discussed below. Partially offsetting these increased expenses was a $9 million decrease in other operations and maintenance expenses, primarily due to the substantial elimination of business and administrative costs previously incurred in support of the divested merchant generation business, including a reduction in pension expense.

Ameren Missouri

Other operations and maintenance expenses were $6 million higher in the first quarter of 2014, as compared with the first quarter of 2013. The following items increased other operations and maintenance expenses between periods:

• An $8 million increase in accrued disposal costs of low-level radioactive nuclear waste at the Callaway energy center.

• A $5 million increase in labor costs, primarily because of wage increases.

• A $4 million increase in energy efficiency program costs due to the requirements of the MEEIA. These costs were offset by increased electric revenues from customer billings, with no overall effect on net income.

Other operations and maintenance expenses decreased between periods because of a $10 million reduction in energy center maintenance costs, primarily due to the absence in 2014 of $6 million of Callaway energy center refueling and maintenance costs incurred in preparation for the second quarter 2013 outage. The outage for 2014 is scheduled for the fourth quarter; no material preparation costs were incurred in the first quarter of 2014.

Ameren Illinois

Pursuant to the provisions of the IEIMA, recoverable electric distribution costs incurred during the year that are not recovered through riders are included in Ameren Illinois’ revenue requirement reconciliation, which results in a corresponding adjustment to electric operating revenues, with no overall effect on net income. These recoverable electric delivery service costs include other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes.

Other operations and maintenance expenses were $24 million higher in the first quarter of 2014, as compared with the first quarter of 2013. The following items increased other operations and maintenance expenses between periods:

• A $9 million increase in energy efficiency and environmental remediation costs. These costs were included in riders and therefore were offset by increased electric and natural gas revenues from customer billings, with no overall effect on net income.

• A $6 million increase in labor costs, primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals.

• A $3 million increase in electric distribution maintenance expenditures, primarily related to increased system repair and vegetation management work.

• A $3 million increase in expenses related to personal injury litigation claims.

Depreciation and Amortization

Ameren Corporation

Depreciation and amortization expenses increased by $6 million in the first quarter of 2014, as compared with the first quarter of 2013, primarily due to increased expenses at Ameren Missouri and Ameren Illinois as discussed below.

Ameren Missouri

Depreciation and amortization expenses increased by $5 million, primarily because of electric distribution capital additions.

Ameren Illinois

Depreciation and amortization expenses increased by $2 million, primarily because of electric distribution capital additions.

Taxes Other Than Income Taxes

Ameren Corporation

Taxes other than income taxes increased by $5 million in the first quarter of 2014, as compared with the first quarter of 2013, primarily due to increased expenses at Ameren Illinois as discussed below.

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Ameren Missouri

Taxes other than income taxes were comparable between periods.

Ameren Illinois

Taxes other than income taxes increased by $4 million, primarily due to an increase in gross receipts taxes as a result of increased natural gas sales. These increased gross receipts taxes were offset by increased gross receipts tax revenues, with no overall effect on net income. See Excise Taxes in Note 1 - Summary of Significant Accounting Policies under Part I, Item 1, of this report for additional information.

Other Income and Expenses

Ameren Corporation

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

Ameren Missouri

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

Ameren Illinois

Other income, net of expenses, was comparable between periods, as increased interest income, primarily related to interest on the IEIMA’s 2013 and 2014 revenue requirement reconciliation regulatory asset balances, offset increased miscellaneous expenses.

Interest Charges

Ameren Corporation

Interest charges decreased by $9 million in the first quarter of 2014, as compared with the first quarter of 2013, primarily due to decreased charges at Ameren Missouri as discussed below.

Ameren Missouri

Interest charges decreased by $8 million, in part, because of interest for pre-MEEIA energy efficiency programs. Additionally, the October 2013 retirement of $200 million of 4.65% senior secured notes and redemption of $44 million of 5.45% pollution control revenue bonds resulted in lower interest charges. This debt was replaced by commercial paper issuances with lower interest rates, therefore reducing the cost of borrowings.

Ameren Illinois

Interest charges were comparable between periods.

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, 2014, and 2013:

	Three Months
	2014		2013
Ameren(a)	39	%	38	%
Ameren Missouri(a)	38	%	32	%
Ameren Illinois(a)	39	%	38	%

(a) 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

The effective tax rate was higher in the first quarter of 2014, as compared with the first quarter of 2013, primarily because of the items detailed at Ameren Missouri and Ameren Illinois below, along with lower permanent tax benefits related to company-owned life insurance in 2014, partially offset by an increase in the reserve for uncertain tax positions in 2013 at Ameren (parent).

Ameren Missouri

The effective tax rate was higher, primarily because of the absence in 2014 of a decrease in the reserve for uncertain tax positions in 2013.

Ameren Illinois

The effective tax rate was higher, primarily because of the decreased impact of tax credits, the amortization of property-related regulatory assets and liabilities and decreases in the reserve for uncertain tax positions on higher pretax income in 2014.

Loss from Discontinued Operations, Net of Taxes

Ameren’s loss from discontinued operations, net of taxes, decreased to $1 million for the three months ended March 31, 2014, from $199 million in the prior-year period. Ameren’s loss from discontinued operations in 2013 was primarily caused by an impairment loss as discussed below.

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. Also during the three months ended March 31, 2013, Ameren adjusted the accumulated deferred income taxes on its balance sheet to reflect the excess of tax basis over financial reporting basis of its stock investment in AER, when it became apparent 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 then-expected tax benefits of $63 million related to the pretax loss from discontinued operations including the impairment charge, during the three months ended March 31, 2013.

See Note 12 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for additional

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information.

LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren's rate-regulated utility operating companies are the principal source of cash from operating activities for the Ameren Companies. A diversified retail customer mix primarily of rate-regulated residential, commercial, and industrial customers 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 temporary capital requirements. Ameren, Ameren Missouri and Ameren Illinois may repay their 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 make significant capital expenditures over the next five years as they invest in their electric and natural gas utility infrastructure to support overall system reliability, environmental compliance, 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 an equity ratio of around 50%, 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.

The use of operating cash flows and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit, as defined by current liabilities exceeding current assets, as was the case at March 31, 2014. The working capital deficit as of March 31, 2014, was primarily the result of current maturities of long-term debt and commercial paper issuances outstanding. In April 2014, Ameren Missouri issued $350 million of long-term notes. The proceeds Ameren Missouri received as a result of the issuance were used to repay a portion of its short-term debt and will be used to repay $104 million of its long-term debt that matures in May 2014. In May 2014, Ameren’s $425 million, 8.875% senior unsecured notes will mature. Ameren expects to use short-term debt to fund this maturity. With the 2012 Credit Agreements, Ameren has access to $2.1 billion of credit capacity of which $1.4 billion was available at March 31, 2014.

The following table presents net cash provided by (used in) operating, investing and financing activities for the three months ended March 31, 2014, and 2013:

	Net Cash Provided By Operating Activities							Net Cash Provided by (Used In) Investing Activities									Net Cash Provided by (Used In) Financing Activities
	2014		2013		Variance			2014			2013			Variance			2014		2013			Variance
Ameren(a) - continuing operations	$	239	$	342	$	(103	)	$	(465	)	$	(291	)	$	(174	)	$	70	$	(99	)	$	169
Ameren(a) - discontinued operations	—		37		(37		)	152			(12		)	164			—		—			—
Ameren Missouri	96		68		28			(204		)	(129		)	(75		)	107		(86		)	193
Ameren Illinois	192		271		(79		)	(214		)	(138		)	(76		)	22		(40		)	62

(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 decreased in the first three months of 2014, compared with the first three months of 2013. The following items contributed to the decrease in cash from operating activities associated with continuing operations during the first three months of 2014, compared with the same period in 2013:

• A $52 million decrease due to the cash flows associated with Ameren Missouri’s under-recovered FAC costs. Deferrals and refunds outpaced recoveries in 2014 by $32 million, while recoveries outpaced deferrals in 2013 by $20 million.

• A $40 million decrease in natural gas commodity over-recovered costs under the PGAs, primarily related to Ameren Illinois.

• A $22 million increase in payments associated with stock-based compensation awards in accordance with the

provisions of the 2006 Omnibus Incentive Compensation Plan.

• A $20 million increase in expenditures for energy efficiency programs that will be recovered through customer billings over time.

• A net $16 million decrease in returns of 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, partially offset by the effect of credit rating upgrades at Ameren Illinois.

• A $15 million increase in the cost of natural gas held in storage at Ameren Illinois because of increased prices.

• Refunds to Ameren Illinois customers of $14 million as required under the provisions of the IEIMA for the 2012 revenue reconciliation adjustment, as compared with no such refunds in the first quarter of 2013.

• The absence in 2014 of $11 million received in the first quarter of 2013 for storm restoration assistance provided to nonaffiliated utilities in 2012, primarily at Ameren Missouri.

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• A $9 million decrease caused by changes in coal inventory levels, as the first quarter of 2013 was affected by delivery disruptions due to flooding.

• An $8 million increase in property tax payments at Ameren Missouri caused by higher assessed property tax values and increased property tax rates.

• A $7 million increase in labor costs at Ameren Illinois, primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals.

• A $5 million increase in payments to contractors at Ameren Illinois for additional reliability, maintenance, and IEIMA projects.

The following items partially offset the decrease in Ameren's cash from operating activities during the first three months of 2014 compared with the same period in 2013:

• Electric and natural gas margins, as discussed in Results of Operations, increased by $71 million, excluding the effect of the noncash IEIMA revenue requirement reconciliation adjustments for 2014 and 2013, as the collections from customers for those adjustments will occur in a subsequent year.

• A $35 decrease in pension and postretirement benefit plan contributions caused by the timing of payments.

• Income tax refunds of $7 million in 2014, compared with income tax payments of $13 million in 2013, resulting primarily from the sale of tax credits in 2014 and the timing of payments.

Ameren’s cash from operating activities associated with discontinued operations decreased in the first three months of 2014, compared with the first three months of 2013. The 2013 cash flows resulted from the operations of the disposed New AER and Elgin, Gibson City and Grand Tower energy centers.

Ameren Missouri

Ameren Missouri’s cash from operating activities increased in the first three months of 2014, compared with the first three months of 2013. The following items contributed to the increase in cash from operating activities during the first three months of 2014, compared with the same period in 2013:

• A $60 million increase in cash collections from customer receivables, primarily due to colder 2014 winter temperatures.

• A $35 million decrease in income tax payments primarily due to the timing of payments.

• Electric and natural gas margins, as discussed in Results of Operations, increased by $20 million.

• A $15 million decrease in pension and postretirement benefit plan contributions caused by the timing of payments.

The following items partially offset the increase in Ameren Missouri’s cash from operating activities during the first three months of 2014, compared with the same period in 2013:

• A $52 million decrease due to the cash flows associated with under-recovered FAC costs. Deferrals and refunds

outpaced recoveries in 2014 by $32 million, while recoveries outpaced deferrals in 2013 by $20 million.

• The absence in 2014 of $10 million received in the first quarter of 2013 for storm restoration assistance provided to nonaffiliated utilities in 2012.

• A $9 million decrease caused by changes in coal inventory levels, as the first quarter of 2013 was affected by delivery disruptions due to flooding.

• An $8 million increase in property tax payments caused by higher assessed property tax values and increased property tax rates.

• A $7 million increase in expenditures for energy efficiency programs that will be recovered through customer billings over time.

• A $5 million decrease in natural gas commodity over-recovered costs under the PGA.

Ameren Illinois

Ameren Illinois’ cash from operating activities decreased in the first three months of 2014, compared with the first three months of 2013. The following items contributed to the decrease in cash from operating activities during the first three months of 2014, compared with the same period in 2013:

• A $54 million decrease in cash collections from customer receivables, primarily due to timing of receipts based on deferred budget billing arrangements and a decline in receipts related to customers switching to alternative retail electric suppliers.

• A $35 million decrease in natural gas commodity over-recovered costs under the PGA.

• A $22 million decrease in income tax refunds primarily due to timing.

• A net $15 milliondecrease in returns of collateral posted with counterparties primarily due to changes in the market prices of power and natural gas and in contracted commodity volumes, partially offset by the effect of credit rating upgrades.

• A $15 million increase in the cost of natural gas held in storage because of increased prices.

• Refunds to customers of $14 million as required under the provisions of the IEIMA for the 2012 revenue reconciliation adjustment, as compared with no such refunds in the first quarter of 2013.

• A $13 million increase in expenditures for energy efficiency programs that will be recovered through customer billings over time.

• A $7 million increase in labor costs, primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals.

• A $5 million increase in payments to contractors for additional reliability, maintenance, and IEIMA projects.

The following items partially offset the decrease in Ameren Illinois’ cash from operating activities during the first three months of 2014, compared with the same period in 2013:

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• Electric and natural gas margins, as discussed in Results of Operations, increased by $43 million, excluding the effect of the noncash IEIMA revenue requirement reconciliation adjustments for 2014 and 2013, as the collections from customers for those adjustments will occur in a subsequent year.

• A $25 million increase in over-recovered purchased power commodity costs.

• A $12 million decrease in pension and postretirement benefit plan contributions caused by the timing of payments.

• A $7 million increase related to accounts payable to affiliates caused by the timing of payments.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities associated with continuing operations in the first three months of 2014 increased compared to the same period in 2013. Capital expenditures increased $167 million as a result of activity at the registrant subsidiaries discussed below as well as increased transmission expenditures at ATXI related to the Illinois Rivers project. In addition, cash flows used in investing activities increased by a net $9 million for payments related to collateral support provided to Marketing Company in the form of a note receivable. This cash collateral support is part of Ameren’s obligation to provide credit support to New AER until December 2, 2015. See Note 12 - Divestiture Transactions and Discontinued Operations in Part I, Item 1, of this report for additional information.

Ameren’s cash provided by investing activities associated with discontinued operations consisted of $152 million received from Rockland Capital for the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers during the first three months of 2014. These proceeds were available to fund continuing operations. During the first three months of 2013, Ameren’s cash used in investing activities associated with discontinued operations were for capital expenditures.

Ameren Missouri’s cash used in investing activities increased during the first three months of 2014, compared with the same period in 2013, due to increased capital expenditures of $51 million primarily for reliability and energy center projects, including the Callaway nuclear reactor head replacement project and Labadie electrostatic precipitator upgrades. In addition, cash flows used in investing activities increased $24 million due to the absence in 2014 of money pool advance repayments.

Ameren Illinois’ cash used in investing activities increased during the first three months of 2014, compared with the same period in 2013, primarily due to an increase in capital expenditures of $82 million for transmission, reliability projects, and IEIMA projects.

We continually review Ameren Missouri's generation portfolio and expected power needs. As a result, Ameren Missouri could modify its plan for generation capacity, the type of generation asset technology that will be employed, and whether

capacity or power may be purchased, among other things. Additionally, the Ameren Companies continually review the reliability of their transmission and distribution systems, expected capacity needs, and opportunities for transmission investments. The timing and amount of investments could vary because of changes in expected capacity, the condition of transmission and distribution systems, and our ability and willingness to pursue transmission investments, among other things. Any changes in 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

In the first three months of 2014, Ameren continued to utilize its commercial paper programs, which had lower interest rates compared with rates available under the 2012 Credit Agreements, to redeem existing long-term indebtedness and reduce the cost of borrowings.

Ameren’s financing activities associated with continuing operations provided net cash of $70 million during the three months ended March 31, 2014, while financing activities used cash of $99 million during the first three months of 2013. Ameren used net commercial paper issuances of $332 million, in part, to fund Ameren Illinois’ redemption of existing long-term indebtedness of $163 million. In comparison, Ameren had no long-term debt redemptions or net commercial paper issuances during the same period in 2013. Dividends paid were comparable between periods.

No financing cash flows were utilized to meet the working capital and investing requirements of our discontinued operations during the first three months of 2014 and 2013.

Ameren Missouri’s financing activities provided cash of $107 million during the three months ended March 31, 2014, compared with 2013, when financing activities used cash of $86 million. In 2014, Ameren Missouri used net commercial paper issuances of $290 million, in part, to repay net money pool borrowings of $105 million. In comparison, Ameren Missouri borrowed $5 million from the money pool in 2013. In addition, common stock dividends decreased $13 million during the three months ended March 31, 2014, compared with the same period in 2013.

Ameren Illinois’ financing activities provided cash of $22 million during the three months ended March 31, 2014, compared with 2013, when financing activities used cash of $40 million. Ameren Illinois had net money pool borrowings of $186 million in 2014, compared with $24 million net repayments in 2013. Ameren Illinois used the net money pool borrowings, to redeem existing long-term indebtedness of $163 million. During the three months ended March 31, 2014, Ameren Illinois did not pay common stock dividends compared to dividend payments of $15 million during the same period in 2013.

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Credit Facility Borrowings and Liquidity

The liquidity needs of Ameren, Ameren Missouri and Ameren Illinois are typically supported through the use of available cash, short-term intercompany borrowings, drawings under committed credit agreements or commercial paper issuances. See Note 3 - Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information on credit agreements, short-term borrowing activity, commercial paper issuances, relevant interest rates, and borrowings under Ameren’s 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 and commercial paper issuances, as of March 31, 2014:

	Expiration	Borrowing Capacity		Credit Available
Amerenand Ameren Missouri:
2012 Missouri Credit Agreement	November 2017	$	1,000	$	1,000
Ameren and Ameren Illinois:
2012 Illinois Credit Agreement	November 2017	1,100		1,100
Ameren:
Less: Commercial paper outstanding		(b)		(700		)
Less: Letters of credit(a)		(b)		(13		)
Total		$	2,100	$	1,387

(a) As of March 31, 2014, $9 million of the letters of credit relate to Ameren's ongoing credit support obligations to New AER. See Note 12 – Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for additional information.

(b) Not applicable.

The 2012 Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren’s and Ameren Missouri’s commercial paper programs. Either of the 2012 Credit Agreements are available to Ameren to support issuances under Ameren’s commercial paper program, subject to borrowing sublimits. The 2012 Missouri Credit Agreement is available to support issuances under Ameren Missouri’s commercial paper program. During 2014, issuances under the Ameren and Ameren Missouri commercial paper programs were available at lower interest rates than the interest rates available under the 2012 Credit Agreements. As such, commercial paper issuances were a preferred source of third-party short-term debt relative to credit facility borrowings.

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In February 2014, FERC issued an order

effective March 17, 2014, authorizing the issuance of up to $1 billion of short-term debt securities for Ameren Missouri. The authorization terminates on March 16, 2016. 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. Ameren Illinois will file for a two-year extension of the FERC short-term borrowing authorization in 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.

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Long-term Debt and Equity

The following table presents the redemptions of long-term debt for the Ameren Companies for the three months ended March 31, 2014, and 2013. The Ameren Companies did not have any issuances of common stock or long-term debt during the first three months of 2014 or 2013. For additional information, see Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report.

		Three Months
	Month Redeemed	2014		2013
Ameren Illinois:
5.90% Series 1993 due 2023(a)	January	$	32	$	—
5.70% 1994A Series due 2024(a)	January	36		—
1993 Series C-1 5.95% due 2026	January	35		—
1993 Series C-2 5.70% due 2026	January	8		—
5.40% 1998A Series due 2028	January	19		—
5.40% 1998B Series due 2028	January	33		—
Total Ameren long-term debt redemptions		$	163	$	—

(a)Less than $1 million principal amount of the bonds remain outstanding after redemption.

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 3 - Short-term Debt and Liquidity and Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report and Note 4 - Short-term Debt and Liquidity and Note 5 - Long-term Debt and Equity Financings under Part II, Item 8, of the Form 10-K for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our credit agreements and in certain of the Ameren Companies’ indentures and articles of incorporation.

At March 31, 2014, 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.

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 2014 (2013 - $97 million declared or 40 cents per share).

The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. The board of directors has not set specific targets or payout parameters when declaring common stock dividends. As in the past, the board of directors is expected to consider various factors, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. Ameren expects its dividend payout ratio to be between 55% and 70% of earnings over the next few years. On April 24, 2014, Ameren’s board of directors declared a quarterly common stock dividend of 40 cents per share payable on June 30, 2014, to stockholders of record on June 11, 2014.

See 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, 2014, none of these circumstances existed at Ameren, Ameren Missouri and Ameren Illinois and, as a result, these companies were not restricted from paying dividends.

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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, 2014, and 2013:

	Three Months
	2014		2013
Ameren Missouri	$	77	$	90
Ameren Illinois	—		15
Dividends paid by Ameren	97		97

Ameren (parent) funds common stock dividends through its available liquidity.

Contractual Obligations

For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7, and Note 15 - Commitments and Contingencies under Part II, Item 8, of the Form 10-K, and Other Obligations in Note 9 - Commitments and Contingencies under Part I, Item 1, of this report. See Note 11 - Retirement Benefits under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan.

At March 31, 2014, 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 $6,251 million, $4,273 million, and $1,908 million respectively.

Off-Balance-Sheet Arrangements

At March 31, 2014, 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. See Note 12 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for Ameren (parent) guarantees and letters of credit issued to support New AER based on the transaction agreement with IPH.

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	Baa2	BBB+	BBB+
Senior unsecured debt	Baa2	BBB	BBB+
Commercial paper	P-2	A-2	F2
Ameren Missouri:
Issuer/corporate credit rating	Baa1	BBB+	BBB+
Secured debt	A2	A	A
Senior unsecured debt	Baa1	BBB+	A-
Commercial paper	P-2	A-2	F2
Ameren Illinois:
Issuer/corporate credit rating	Baa1	BBB+	BBB
Secured debt	A2	A	A-
Senior unsecured debt	Baa1	BBB+	BBB+

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 the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and negatively impact earnings. Cash collateral postings and prepayments with external parties, including postings related to exchange-traded contracts, at March 31, 2014, were $20 million, $17 million, and $3 million at Ameren, Ameren Missouri and Ameren Illinois, respectively. Cash collateral posted by external counterparties with Ameren and Ameren Illinois was $2 million and $2 million, respectively, at March 31, 2014. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at March 31, 2014, 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 $116 million, $51 million, and $65 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, 2014, 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 would not be required to post additional collateral or other assurances for certain trade obligations. If market prices were 15% lower than March 31, 2014, levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren or Ameren Illinois could be required to post additional collateral or other assurances for certain trade obligations up to $9 million and $9 million, respectively.

The balance of Marketing Company’s note payable to Ameren for cash collateral requirements was $27 million at March 31, 2014; it will vary until December 2, 2015, as cash collateral requirements for New AER will change. Changes in commodity prices could trigger additional collateral postings and prepayments for New AER and thus affect the balance of the

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note. If market prices were 15% higher than March 31, 2014, levels in the next 12 months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren could be required to provide additional credit support to IPH up to $121 million. If market prices were 15% lower than March 31, 2014, levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren could be required to provide IPH with additional credit support up to $28 million. In addition, as of March 31, 2014, and using market prices as of that date, if Ameren's credit ratings had been below investment grade, Ameren could have been required to post additional cash collateral in support of New AER in the amount of $43 million.

See Note 12 – Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for information regarding Ameren (parent) guarantees.

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. Ameren Missouri and Ameren Illinois 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. Ameren intends to allocate its capital resources to those business opportunities that offer the most attractive risk-adjusted return potential.

Below are some key trends, events, and uncertainties that are reasonably likely to affect the Ameren Companies' results of operations, financial condition, or liquidity, as well as their ability to achieve strategic and financial objectives, for 2014 and beyond.

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.

• Ameren continues to pursue its plans to invest in FERC-regulated electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The first project, Illinois Rivers, involves the construction of a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. ATXI obtained a certificate of public convenience and necessity and project approval from the ICC for the entire Illinois Rivers project. A full range of construction activities is scheduled in 2014. The first sections of the Illinois Rivers project are expected to be completed in 2016. The last section of this project is expected to be completed by 2019. The Spoon River project in northwest Illinois and the Mark Twain project in northeast

Missouri are the other two projects approved by MISO. These two projects are expected to be completed in 2018. ATXI plans to request a certificate of public convenience and necessity from the ICC for the Spoon River project in the third quarter of 2014. An ICC decision on this filing is expected in 2015. The total investment in these three projects is expected to be $1.4 billion through 2019. ATXI is currently reviewing, and expects during 2014 to update, the estimated cost of the Illinois Rivers project incorporating the final route approved by the ICC, which is longer than originally proposed. Separate from the ATXI projects discussed above, Ameren Illinois expects to invest approximately $850 million in electric transmission assets through 2018 to address load growth and reliability requirements.

• In July 2013, Illinois enacted the Natural Gas Consumer, Safety and Reliability Act, which encourages Illinois natural gas utilities to accelerate modernization of the state's natural gas infrastructure and provides additional ICC oversight of natural gas utility performance. The law allows natural gas utilities the option to file for, and requires the ICC to approve, a rate rider mechanism to recover costs of certain natural gas infrastructure investments made between rate cases. The law does not require a minimum level of investment. Ameren Illinois expects to begin including investments under this regulatory framework in 2015. Ameren Illinois' decision to accelerate modernization of its natural gas infrastructure under this regulatory framework is dependent upon multiple considerations, including the allowed return on equity under this framework compared with other Ameren and Ameren Illinois investment options.

• 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 customer billings for that year. Consequently, Ameren Illinois' 2014 electric delivery service revenues will be based on its 2014 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. The 2014 revenue requirement is expected to be higher than the 2013 revenue requirement, due to an expected increase in recoverable costs, rate base growth, and expected increase in the monthly average yields of 30-year United States Treasury bonds.

• In December 2013, the ICC issued an order with respect to Ameren Illinois' annual update IEIMA filing. The ICC approved a net $45 million decrease in Ameren Illinois' electric delivery service rates, which represents an annual revenue requirement increase of $23 million primarily due to higher recoverable costs in 2012 compared to 2011, offset by a $68 million refund to customers relating to the 2012 revenue requirement reconciliation. The ICC decision issued in December 2013 established new rates that became effective January 1, 2014. These rates will affect Ameren Illinois' cash flows during 2014, but not its operating revenues, which will instead be determined by the IEIMA's 2014 revenue requirement reconciliation. The 2014 revenue requirement reconciliation will be reflected as a regulatory

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asset or liability that will be collected from or refunded to customers in 2016.

• In April 2014, Ameren Illinois filed its annual electric delivery service formula rate update with the ICC based on 2013 recoverable costs and expected net plant additions for 2014. Pending ICC approval, the update filing will result in a $206 million increase in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2015. An ICC decision in this April 2014 filing is expected by December 2014 and will establish rates for 2015. These rates will affect Ameren Illinois' cash flows during 2015.

• In December 2013, the ICC issued an order that authorized a $32 million increase in Ameren Illinois’ annual natural gas delivery service revenues. This request was based on a future test year of 2014, which improves the ability to earn returns allowed by regulators. The new rates became effective January 1, 2014.

• In February 2014, Ameren Missouri’s largest customer, Noranda, and 37 residential customers filed an earnings complaint case and a rate shift complaint case with the MoPSC. In the earnings complaint case, Noranda and the residential customers asserted that Ameren Missouri’s electric service business is earning more than the 9.8% return on equity authorized in the MoPSC's December 2012 electric rate order and requested the MoPSC to approve a $67 million reduction to Ameren Missouri’s annual revenue requirement. Included in Noranda’s request is a reduction of Ameren Missouri’s authorized return on equity to 9.4%. Ameren Missouri does not believe that a reduction in electric service rates is justified and will file testimony that supports that position, which is consistent with Ameren Missouri’s expected July 2014 rate case filing. The rate shift complaint case seeks to reduce Noranda’s electricity cost with an offsetting increase in electricity cost for Ameren Missouri’s other customers. While the rate shift proposal is revenue neutral to Ameren Missouri, Ameren Missouri does not believe that the proposed reduction to Noranda’s electric rates, which are significantly below Ameren Missouri’s cost of service, is appropriate or in the best interests of Ameren Missouri’s other electric customers. The MoOPC and MIEC have intervened in the earnings complaint case. While the MoPSC has no time requirement by which it must issue an order in these cases, it has adopted procedural schedules that would render a decision in the rate shift case by August 6, 2014, and in the earnings complaint case by September 26, 2014. If the MoPSC approves Noranda’s earnings complaint case as currently filed on September 26, 2014, Ameren’s and Ameren Missouri’s 2014 earnings would be reduced by an estimated $10 million.

• Ameren Missouri will file an electric service rate case by July 15, 2014, seeking an increase to its annual revenue requirement. The MoPSC has 11 months from when Ameren Missouri files its request to issue an order.

• As we continue to experience cost increases and make infrastructure investments, 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, as necessary, legislative

solutions to address cost recovery pressures and to support investment in their energy infrastructure. These pressures include limited economic growth in their service territories, customer conservation efforts, the impacts of energy efficiency programs, increased investments and expected future investments for environmental compliance, system reliability improvements, and new generation 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.

• 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’s and Ameren Missouri’s results of operations, financial position, and liquidity could be adversely affected if Ameren Missouri’s remaining liability insurance claims of $68 million as of March 31, 2014, are not paid by insurers.

• Ameren Missouri's next scheduled refueling and maintenance outage at its Callaway energy center will be in the fall of 2014. During a scheduled outage, which occurs every 18 months, maintenance expenses increase relative to non-outage years. Additionally, depending on the availability of its other generation sources and the market prices for power, Ameren Missouri's purchased power costs may increase and the amount of excess power available for sale may decrease versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC, resulting in limited impacts to earnings. Additional maintenance costs incurred during the outage will not be fully recovered in 2014, 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 capacity.

• As of March 31, 2014, Ameren Missouri had capitalized $69 million of costs incurred to license additional nuclear generation at its Callaway energy site. If efforts are abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination was made.

• Environmental regulations, as well as future initiatives, including those related to greenhouse gas emissions, or other actions taken by the EPA, could result in significant increases in capital expenditures and operating costs. These expenses could be prohibitive at some of Ameren Missouri's coal-fired energy centers, particularly at its Meramec energy center. Ameren Missouri's capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances as well as prolonged periods before recovery of these investments occur. Ameren's and Ameren Missouri's earnings may

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benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered timely in rates.

• Both Ameren Illinois and ATXI have FERC authorization to employ a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. With the projected rates that became effective on January 1, 2014, Ameren Illinois’ 2014 revenue requirement for its electric transmission business is expected to increase by $15 million over 2013 levels due to rate base growth. With the projected rates that became effective on January 1, 2014, ATXI’s 2014 revenue requirement for its electric transmission business is expected to increase by $21 million over 2013 levels due to rate base growth, primarily relating to the Illinois Rivers project.

• In November 2013, a customer group filed a complaint case with FERC seeking a reduction in the allowed return on common equity to 9.15%, as well as a limit on the common equity ratio, under the MISO tariff. Currently, the FERC-allowed return on common equity for MISO transmission owners is 12.38%. This complaint case could result in a reduction to Ameren Illinois' and ATXI's allowed return on common equity. That reduction could also result in a refund for transmission service revenues earned after the filing of the complaint case in November 2013. FERC has not issued an order in this case, and it is under no deadline to do so.

• For additional information regarding recent rate orders and related appeals, pending requests filed with state and federal regulatory commissions, and Taum Sauk matters, see Note 2 – Rate and Regulatory Matters, Note 9 – Commitments and Contingencies, and Note 10 – Callaway Energy Center under Part I, Item 1, of this report and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K.

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.

• The use of operating cash flows and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit, as defined by current liabilities exceeding current assets, as was the case at March 31, 2014. The working capital deficit as of March 31, 2014, was primarily the result of current maturities of long-term debt and commercial paper issuances outstanding. In April 2014, Ameren Missouri issued $350 million of long-term notes. The proceeds Ameren Missouri received as a result of the issuance were used to repay a portion of its short-term debt and will be used to repay $104 million of its long-term debt that matures in May 2014. In May 2014, Ameren’s $425 million 8.875% senior unsecured notes will mature. Ameren expects to use short-term debt to fund this maturity. At

current market rates, short-term debt has a lower interest rate than the 8.875% rate on the senior unsecured notes.With the 2012 Credit Agreements, Ameren has access to $2.1 billion of credit capacity of which $1.4 billion was available at March 31, 2014.

• Ameren expects its cash used for capital expenditures and dividends to exceed cash provided by operating activities over the next few years.

• Ameren Illinois intends to finance its 2014 capital spending while maintaining an approximate 50% common equity capital structure. To accomplish that desired capital structure, Ameren Illinois does not anticipate paying dividends to Ameren during 2014.

• As of March 31, 2014, Ameren had $404 million in tax benefits from federal and state net operating loss carryforwards (Ameren Missouri – $62 million and Ameren Illinois – $95 million) and $110 million in federal and state income tax credit carryforwards (Ameren Missouri – $12 million and Ameren Illinois – none). Consistent with the tax allocation agreement between Ameren and its subsidiaries, these carryforwards are expected to partially offset income tax liabilities in 2014 for Ameren Missouri and for Ameren and Ameren Illinois into 2016. In addition, Ameren has $85 million of expected income tax refunds and state overpayments that will offset income tax liabilities into 2016. These tax benefits, primarily at the Ameren (parent) level, when realized, will be available to finance electric transmission investments, specifically ATXI's Illinois Rivers project. These tax benefits are projected to reduce or eliminate Ameren's need to issue additional equity to fund these investments over the next few years.

• 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. Final regulations related to this guidance were issued in September 2013. Ameren expects to use $50 million (Ameren Missouri - $30 million and Ameren Illinois - $20 million) in federal income tax net operating loss carryforward benefits to offset tax liabilities related to the accounting method change that Ameren expects to file with the IRS in 2014 in connection with this new guidance.

• Ameren has entered into an agreement with a buyer to sell the Meredosia energy center in 2014, provided certain closing conditions are met, for $25 million and the assumption of certain liabilities. Any proceeds received or gain recognized in connection with a sale would be reflected in discontinued operations.

• The Ameren Companies have multiyear credit agreements that cumulatively provide $2.1 billion of credit through November 14, 2017. See Note 3 – 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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity

prices, and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset or index. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risk 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 objectives are 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.

There have been no material changes to the quantitative and qualitative disclosures about interest rate risk, credit risk, equity price risk, and commodity price risk included in the Form 10-K. See Item 7A, under Part II, of the Form 10-K for a more detailed discussion of our market risk.

Commodity Price Risk

The following table presents, as of March 31, 2014, the percentages of the projected required supply of coal and coal transportation for Ameren Missouri's coal-fired energy centers, nuclear fuel for Ameren Missouri’s Callaway energy center, natural gas for both Ameren Missouri's and Ameren Illinois’ retail distribution as well as Ameren Missouri’s CTs, and purchased power for Ameren Illinois, which does not own generation, that are price-hedged over the period 2014 through 2018. The projected required supply of these commodities could be significantly affected by changes in our assumptions about customer demand for our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.

	2014		2015		2016 - 2018
Ameren:
Coal	100	%	100	%	72	%
Coal transportation	100		100		80
Nuclear fuel	100		100		78
Natural gas for generation	30		23		1
Natural gas for distribution(a)	33		13		4
Purchased power for Ameren Illinois(b)	100		73		17
Ameren Missouri:
Coal	100	%	100	%	72	%
Coal transportation	100		100		80
Nuclear fuel	100		100		78
Natural gas for generation	30		23		1
Natural gas for distribution(a)	31		25		14
Ameren Illinois:
Natural gas for distribution(a)	33	%	12	%	3	%
Purchased power(b)	100		73		17

(a) Represents the percentage of natural gas price hedged for peak winter season of November through March. The year 2014 represents November 2014 through March 2015. The year 2015 represents November 2015 through March 2016. This continues each successive year through March 2019.

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

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

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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, 2014. We use various methods to determine the fair value of our contracts. In accordance with authoritative accounting guidance for fair value hierarchy levels, the sources we used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). See Note 7 - Fair Value Measurements under Part I, Item 1, of this report for further information regarding the methods used to determine the fair value of these contracts.

Three Months Ended March 31, 2014	Ameren Missouri			Ameren Illinois			Ameren
Fair value of contracts at beginning of year, net	$	9		$	(153	)	$	(144	)
Contracts realized or otherwise settled during the period	(7		)	10			3
Changes in fair values attributable to changes in valuation technique and assumptions	—			—			—
Fair value of new contracts entered into during the period	—			—			—
Other changes in fair value	(2		)	(1		)	(3		)
Fair value of contracts outstanding at end of period, net	$	—		$	(144	)	$	(144	)

The following table presents maturities of derivative contracts as of March 31, 2014, 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 Missouri:
Level 1	$	(1	)	$	—		$	—		$	—		$	(1	)
Level 2(a)	(1		)	(3		)	(1		)	—			(5		)
Level 3(b)	7			(1		)	—			—			6
Total	$	5		$	(4	)	$	(1	)	$	—		$	—
Ameren Illinois:
Level 1	$	—		$	—		$	—		$	—		$	—
Level 2(a)	(11		)	(13		)	—			—			(24		)
Level 3(b)	(8		)	(19		)	(20		)	(73		)	(120		)
Total	$	(19	)	$	(32	)	$	(20	)	$	(73	)	$	(144	)
Ameren:
Level 1	$	(1	)	$	—		$	—		$	—		$	(1	)
Level 2(a)	(12		)	(16		)	(1		)	—			(29		)
Level 3(b)	(1		)	(20		)	(20		)	(73		)	(114		)
Total	$	(14	)	$	(36	)	$	(21	)	$	(73	)	$	(144	)

(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 information from external sources, historical results, and our estimates. Level 3 also includes option contract values based on a Black-Scholes model.

ITEM 4. CONTROLS AND PROCEDURES.

(a) Evaluation of Disclosure Controls and Procedures

As of March 31, 2014, 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 on those evaluations, as of March 31, 2014, the principal executive officer and the 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 its principal financial officers, to allow timely decisions regarding required disclosure.

(b) Changes in Internal Controls over Financial Reporting

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.

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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, which are discussed in Note 2 - Rate and Regulatory Matters, Note 9 - Commitments and Contingencies, Note 10 - Callaway Energy Center, and Note 12 - Divestiture Transactions and Discontinued Operations 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:

• Ameren Illinois' appeals of the ICC's September 2012, December 2012, and December 2013 electric rate orders and the ICC’s December 2013 natural gas rate order;

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

• complaint cases filed by Noranda and 37 residential customers with the MoPSC in February 2014 requesting a reduction to Ameren Missouri's electric rates, including a reduction to its allowed return on equity, and certain rate shift changes;

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

• Ameren Illinois' request for rehearing of FERC's July 2012 and June 2013 orders regarding the inclusion of acquisition premiums in Ameren Illinois' electric transmission rates;

• the EPA's Clean Air Act-related litigation against Ameren Missouri;

• 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;

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

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

ITEM 1A. RISK FACTORS.

There have been no material changes to the risk factors disclosed in Part I, Item 1A, Risk Factors in the Form 10-K filed by Ameren, Ameren Missouri and Ameren Illinois with the SEC.

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

The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of Regulation S-K:

Period	(a) Total  Number of Shares (or Units) Purchased(a)	(b) Average  Price Paid per Share (or Unit)		(c) Total Number of  Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
January 1 - January 31, 2014	17,979	$	35.66	—	—
February 1 - February 28, 2014	—	—		—	—
March 1 - March 31, 2014	467,355	40.60		—	—
Total	485,334	$	40.62	—	—

(a) Included in January were 17,979 shares of Ameren common stock purchased 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 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, 2014 to March 31, 2014.

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:
Material Contracts
10.1	Ameren Companies	2014 Ameren Executive Incentive Plan*
10.2	Ameren Companies	Formula for Determining 2014 Target Performance Share Unit Awards to be Issued to Named Executive Officers*
10.3	Ameren Companies	Form of Performance Share Unit Award Agreement for Awards Issued in 2014 pursuant to 2006 Omnibus Incentive Compensation Plan*
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 Files
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

64

The file number references for the Ameren Companies’ filings with the SEC are: Ameren, 1-14756; Ameren Missouri, 1-2967; and Ameren Illinois, 1-3672.

* Compensatory plan or arrangement.

** Attached as Exhibit 101 to this report is the following financial information for each of the Ameren Companies’ Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statement of Income for the three months ended March 31, 2014, and 2013, (ii) the Consolidated Statement of Comprehensive Income for the three months ended March 31, 2014, and 2013, (iii) the Consolidated Balance Sheet at March 31, 2014, and December 31, 2013, (iv) the Consolidated Statement of Cash Flows for the three months ended March 31, 2014, and 2013, and (v) the Combined Notes to the Financial Statements for the three months ended March 31, 2014.

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 12, 2014

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EX-10.1

Exhibit 10.1

2014 AMEREN EXECUTIVE INCENTIVE PLAN FOR OFFICERS

SUMMARY

The Ameren Executive Incentive Plan (EIP) is intended to reward eligible Officers for their contributions to Ameren’s success. The EIP rewards Officers for Ameren’s earnings per share (EPS) results, safety performance results and individual performance. The EIP is approved by the Human Resources Committee of Ameren’s Board of Directors (“Committee”). Ameren reserves the right at its sole discretion to revise, modify, suspend, continue or discontinue the EIP after the current plan year.

EIP ELIGIBILITY

All Officers who are actively employed on December 31, 2014 are eligible to participate in the EIP pursuant to the terms described herein. Additionally, Officers who terminate employment during the plan year (or following the plan year but before the award is paid) because they retire, die, become disabled, or are involuntarily terminated as a result of a reduction in force, elimination of position, or change in strategic demand, are eligible to participate in the EIP pursuant to the terms described herein. Officers who voluntarily or involuntarily terminate employment for any reason other than those reasons described in the prior sentence during the plan year or following the plan year but before awards are paid, forfeit participation in the EIP.

AWARD OPPORTUNITIES

Award opportunity percentages are set by the Human Resources Committee of the Board of Directors. Officers will receive individual communication regarding their incentive target opportunity expressed as a percentage of their 2014 base salary. 2014 base salary is defined, generally, as the salary at the end of the plan year or at the time of eligible termination, if earlier. However, if salary changes during the plan year, proration will apply as specified in “Job changes during plan year (e.g. salary increase, new role, etc.)” under “Impact of Employment Events” (below).

PLAN STRUCTURE

The EIP is designed to reward Officers for their contributions to Ameren’s success. This is accomplished by rewarding Officers for the achievement of EPS goals, safety performance and their own personal contributions to Ameren’s performance. The EIP has four primary components: (1) performance metrics (EPS & Safety); (2) a base award; (3) an individual performance modifier; and (4) an individual incentive payout. These components are described in more detail below.

Performance Metrics (EPS & Safety)

All Officers should be focused on both the financial and operational success of our organization. Thus, Officers will be rewarded for financial (EPS) and safety (Lost Workday Away cases or “LWA”) performance. These metrics are weighted as follows: 90% based on EPS and 10% based on safety LWA performance.

Three levels of performance achievement will be established to reward eligible Officers for results achieved in EPS & safety performance. Achievement between the established levels will be interpolated. The three levels are defined as follows:

1. Threshold: Threshold is the minimum level of Ameren performance achievement necessary for incentive funds to be available. This level must be achieved to justify the payment based on our fiduciary responsibility to our shareholders.

2. Target: This is the targeted level of Ameren EPS & safety achievement.

3. Maximum: This level shares higher rewards in years of outstanding performance. This level will be very difficult to achieve, but in years of outstanding performance, Officers will share in Ameren’s success.

Base Award

Following the conclusion of the plan year, Ameren’s EPS & safety performance will be measured. EPS achievement levels may be adjusted to include or exclude specified items of an unusual nature or non-operating or significant events not anticipated in the business plan when EPS achievement levels were established as determined by the Committee at its sole discretion and as permitted by the Ameren Corporation 2014 Omnibus Incentive Compensation Plan (“Plan”). Using these performance results, a formulaic base award will be determined for each Officer. As described below, this formulaic base award will then be subject to modification based on the Officer’s individual performance.

Individual Performance Modifier

The base award for each Officer may be adjusted up by as much as 50% or down by as much as 50% with the ability to pay zero for poor or non-performance, based on the Officer's individual contributions and performance during the plan year, as determined by the Committee at its sole discretion and as permitted by the Plan. Demonstrated leadership and the achievement of key operational goals will be considered when further modifying the base award for each Officer.

Individual Incentive Payout

The individual incentive payout represents the actual incentive award an Officer will receive as a result of both Ameren’s performance and the Officer’s own individual performance. Subject to the terms described herein, the maximum payout under the EIP is 200% of the Officer's target incentive opportunity.

EIP PAYOUT

Awards will be paid by March 15, 2015.

Impact of Employment Events

The following table shows the impact of various employment events.

Employment Event	Payout
Hire during plan year	The award pays out by March 15, 2015 based on 2014 base salary and EPS & safety performance, pro rata for the number of days worked in the plan year and subject to the individual performance modifier.
Job changes during plan year (e.g. salary increase, new role, etc.)	The award pays out by March 15, 2015, pro rata based on any changes in target incentive opportunity, salary, performance metric and/or plan eligibility for each respective time period during the plan year, and subject to the individual performance modifier.
Death, disability or retirement during plan year or following plan year but before award is paid	The award pays out by March 15, 2015 based on 2014 base salary and EPS & safety performance, pro rata for the number of days worked in the plan year, and subject to the individual performance modifier.
Paid, unpaid or military leave of absence during plan year	Treated as a period of normal employment.
Involuntary termination as a result of a reduction in force, elimination of position, or change in strategic demand	The award pays out by March 15, 2015 based on 2014 base salary and EPS & safety performance, pro rata for the number of days worked in the plan year, and subject to the individual performance modifier, assuming the eligible participant signed and returned the Company’s approved general release and waiver within 45 days of termination and the seven day revocation period (from the date of signed release) has expired.
Other involuntary or voluntary termination	No payout if termination occurs during the plan year or following the plan year but before award is paid.
Change of control	The impact of Change of Control is described in the Second Amended and Restated Ameren Corporation Change Of Control Severance Plan, as amended. Please refer to this document for further information.

The Committee will review and has the authority to approve the final amount of payment. All payments are within the complete and sole discretion of the Committee. The final payment granted is final and conclusive and not subject to review.

CONTACT

Questions regarding this plan may be directed to the Director, Talent Management & Executive Compensation at 314.554.2049, or the Executive Compensation Manager at 314.206.0642.

ADMINISTRATION

This EIP and the employee’s rights hereunder are subject to all the terms and conditions of the Plan, as the same may be amended from time to time, as well as to such rules and regulations as the Committee or its designee may adopt for administration of the Plan. The Committee, or its designee, is authorized to administer, construe and make all determinations necessary or appropriate to the administration of this EIP, all of which will be binding upon participants. If any provision of this EIP conflicts in any manner with the Plan, the terms of the Plan shall control.

MISCELLANEOUS

No employee shall have any claim or right to receive an award under this EIP. Neither this EIP nor any action taken hereunder shall be construed as giving an employee any right to be retained by Ameren Corporation or any of its subsidiaries or to limit in any way the right of Ameren Corporation or any of its subsidiaries to change such employee’s compensation or other benefits or to terminate the employment or service of such person with or without cause. For purposes of this EIP, the transfer of employment by an employee between subsidiaries shall not be deemed a termination of the employee’s employment.

EX-10.2

Exhibit 10.2

FORMULA FOR DETERMINING 2014 TARGET PERFORMANCE SHARE UNIT

AWARDS TO BE ISSUED TO NAMED EXECUTIVE OFFICERS

The target number of performance share units to be issued to each Named Executive Officer listed below for 2014 will be determined in accordance with the following formula:

2014 Target Number PSU Awards	=	Base Salary as of 1/1/14	x	Long‑Term Incentive Target listed below
		Average closing price of Ameren Corporation Common Stock on The New York Stock Exchange for each trading day in December 2013

NAMED EXECUTIVE OFFICER	LONG-TERM INCENTIVE TARGET AS PERCENT OF BASE SALARY
Voss	325%
Lyons	175%
Baxter	175%
Sullivan	N/A1
Naslund	150%
Nelson	160%

^{_______________________________________} 

¹ Mr. Sullivan’s employment with the Company terminated as of December 2, 2013 and, accordingly, he did not receive a 2014 PSUP award.

EX-10.3

Exhibit 10.3

Performance Share Unit

Award Agreement

Ameren Corporation

2006 Omnibus Incentive Compensation Plan

January 1, 2014

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Ameren Corporation

Performance Share Unit Award Agreement

THIS AGREEMENT, effective January 1, 2014, represents the grant of Performance Share Units by Ameren Corporation (the “Company”), to the Participant named below, pursuant to the provisions of the Ameren Corporation 2006 Omnibus Incentive Compensation Plan (as the same may be amended from time to time, the “Plan”). The number of Shares ultimately earned and paid, if any, for such Performance Share Units will be determined pursuant to Section 3 of this Agreement.

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

1.Grant Information. The individual named below has been selected to be a Participant in the Plan, as specified below:

(a)Participant:

(b)Target Number of Performance Share Units:

2.Performance Period. The performance period begins on January 1, 2014, and ends on December 31, 2016 (“Performance Period”).

3.Performance Grid. The number of Performance Share Units earned by the Participant under this Agreement will be determined in accordance with the following grid. If the actual performance results fall between two of the categories listed below, straight-line interpolation will be used to determine the amount earned. Payouts that otherwise would have been more than 100% of Target will be capped at Target if the Company’s total shareholder return (“TSR”) is negative over the three-year period. TSR shall be calculated in the manner set forth in Exhibit 1 hereto and compared to the peer group identified in Exhibit 1.

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Ameren’s Percentile in Total Shareholder Return vs. Utility Peers During the Performance Period	Payout-Percent of Target Performance Share Units Granted
90th percentile +	200%
70th percentile	150%
50th percentile	100%
30th percentile	50%
<30th percentile but three-year average GAAP Earnings Per Share (“EPS”) GAAP EPS achievement levels could be adjusted to include or exclude specified items of an unusual or non recurring nature as determined by the Committee at its sole discretion and as permitted by the Plan. reaches or exceeds the average of the Executive Incentive Plan (“EIP”) threshold levels for 2014, 2015 and 2016	30%
<30th percentile and three-year average GAAP EPS1 does not reach the average of the EIP threshold levels for 2014, 2015 and 2016	0% (no payout)

4.Calculation of Earned Performance Share Units. The Committee, in its sole discretion, will determine the number of Performance Share Units earned by the Participant at the end of the Performance Period based on the performance of the Company, calculated using the performance grid set forth in Section 3 of this Agreement.

5.Vesting of Performance Share Units. Subject to provisions set forth in Section 9 of this Agreement related to a Change of Control (as defined in the Second Amended and Restated Ameren Corporation Change of Control Severance Plan, as amended (the “Change of Control Severance Plan”)) of the Company and Section 10 of this Agreement relating to termination for Cause (as defined in the Change of Control Severance Plan), the Performance Share Units will vest as set forth below:

(a) Provided the Participant has continued employment through such date, one hundred percent (100%) of the earned Performance Share Units will vest on December 31, 2016; or

(b) Provided the Participant has continued employment through the date of his death and such death occurs prior to December 31, 2016, the Participant will be entitled to a prorated award based on the Target Number of Performance Share Units set forth in Section 1(b) of this Agreement plus accrued dividends as of the date of his death, with such prorated number based upon the total number of days the Participant worked during the Performance Period; or

(c) Provided the Participant has continued employment through the date of his Disability (as defined in Code Section 409A), and such Disability occurs prior to December 31, 2016, one hundred percent (100%) of the Performance Share Units he would have earned had he remained employed by the Company for the entire Performance Period will vest on December 31, 2016, based on the actual performance of the Company during the entire Performance Period; or

______________________________

¹ GAAP EPS achievement levels could be adjusted to include or exclude specified items of an unusual or non recurring nature as determined by the Committee at its sole discretion and as permitted by the Plan.

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(d) Provided the Participant has continued employment through the date of retirement (as described below) and such retirement occurs before December 31, 2016, the following vesting schedule shall be applicable to the Performance Share Units:

(i) If the Participant retires at an age of 55 or greater with five (5) or more years of service (as defined in the Ameren Retirement Plan, as supplemented and amended from time to time) and is not otherwise described in paragraph (ii) below- the Participant is entitled to receive a prorated portion of the Performance Share Units that would have been earned had the Participant remained employed by the Company for the entire Performance Period, based on the actual performance of the Company during the entire Performance Period, with the prorated number based upon the total number of days the Participant worked during the Performance Period; or

(ii) If the Participant retires after reaching age 62 with ten (10) or more years of service (as defined in the Ameren Retirement Plan, as supplemented and amended from time to time)- the Participant is entitled to receive one hundred percent (100%) of the Performance Share Units that would have been earned had the Participant remained employed by the Company for the entire Performance Period based on the actual performance of the Company during the entire Performance Period.

Termination of employment during the Performance Period for any reason other than death, Disability, retirement as described above, or on or after a Change of Control in accordance with Section 9 will require forfeiture of this entire award, with no payment to the Participant.

6.Form and Timing of Payment. All payments of vested Performance Share Units pursuant to this Agreement will be made in the form of Shares. Except as otherwise provided in this Agreement, payment will be made upon the earlier to occur of the following:

(a)February, 2017 or as soon as practicable thereafter (but in no event later than March 15, 2017);

(b)The Participant’s death or as soon as practicable thereafter (but in no event later than March 15 of the calendar year following the year in which the Participant’s death occurred).

Fractional Performance Share Units that constitute less than a single share may be rounded to the nearest full share or converted to cash, at the Company’s option.

7.Right as Shareholder. Except as specifically set forth in this Agreement, the Participant shall not have voting or any other rights as a shareholder of the Company with respect to Performance Share Units. The Participant will obtain full voting and other rights as a shareholder of the Company upon the payment of the Performance Share Units in Shares as provided in Section 6 or 9 of this Agreement.

8.Dividends. The Participant shall be entitled to receive dividend equivalents, which represent the right to receive Shares measured by the dividend payable with respect to the

- 4 -

corresponding number of Performance Share Units. Dividend equivalents on Performance Share Units will accrue and be reinvested into additional Performance Share Units throughout the three-year Performance Period. The additional Shares will be paid as set forth in Section 6 or 9 of this Agreement. Participants will not be entitled to any dividend equivalent amount on Performance Share Units covered by this Agreement which are not ultimately earned.

9.Change of Control.

(a)Company No Longer Exists. Upon a Change of Control which occurs on or before December 31, 2016 in which the Company ceases to exist or is no longer publicly traded on the New York Stock Exchange or the NASDAQ Stock Market, Sections 3, 4, 5 and 6 of this Agreement, unless otherwise provided, shall no longer apply and instead, the amount distributed under this Award shall be based on the Target Number of Performance Share Units awarded as set forth in Section 1(b) of this Agreement plus any accrued dividends and interest as follows:

(i) The amount underlying this Award as of the date of the Change of Control shall equal the value of one Share based on the closing price on the New York Stock Exchange on the last trading day prior to the date of the Change of Control multiplied by the sum of the Target Number of Performance Share Units awarded as set forth in section 1(b) of this Agreement plus the additional Performance Share Units attributable to accrued dividends as of the date of the Change of Control;

(ii) Interest on this Award shall accrue based on the prime rate (adjusted on the first day of each calendar quarter) as published in the “Money Rates” section in the Wall Street Journal from the date of the Change of Control until this Award is distributed or forfeited;

(iii) If the Participant remains employed with the Company or its successor until the last day of the Performance Period, this Award, including interest, shall be paid to the Participant in an immediate lump sum on January 1, 2017, or as soon as practicable thereafter (but in no event later than March 15, 2017);

(iv) If the Participant retired (as described in Section 5(d) of this Agreement) or terminated employment due to Disability prior to the Change of Control under Section 9(a) of this Agreement, the Participant shall immediately receive payment under this Award upon such Change of Control;

(v) If the Participant remains employed with the Company or its successor until his death or Disability which occurs after the Change of Control and before the last day of the Performance Period, the Participant (or his estate or designated beneficiary) shall immediately receive payment under this Award, including interest (if any), upon such death or Disability;

(vi) If the Participant has a qualifying termination (as defined in Section 9(c) of this Agreement) before the last day of the Performance Period, the Participant shall immediately receive payment under this Award, including interest (if any), upon such termination; and

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(vii) In the event the Participant terminates employment before the end of the Performance Period for any reason other than as described in Sections (iv), (v) or (vi) above, this Award, including interest (if any), will immediately be forfeited.

(b)Company Continues to Exist. If there is a Change of Control of the Company but the Company continues in existence and remains a publicly traded company on the New York Stock Exchange or the NASDAQ Stock Market, the Performance Share Units will pay out upon the earliest to occur of the following:

(i) As set forth in Section 6 (“Form and Timing of Payments”) of this Agreement in accordance with the vesting provisions of Sections 5(a), (b), (c) and (d) of this Agreement; or

(ii) If the Participant experiences a qualifying termination (as defined in Section 9(c) of this Agreement) during the two-year period following the Change of Control and the termination occurs prior to January 1, 2017, one hundred percent (100%) of the Performance Share Units he would have earned had he remained employed by the Company for the entire Performance Period based on the actual performance of the Company during the entire Performance Period. Such Performance Share Units will vest on December 31, 2016 and the vested Performance Share Units will be paid in Shares on January 1, 2017 or as soon as practicable thereafter (but in no event later than March 15, 2017).

(c)Qualifying Termination. For purposes of Sections 9(a)(vi) and 9(b)(ii) of this Agreement, a qualifying termination means (i) an involuntary termination without Cause, (ii) for Change of Control Severance Plan participants, a voluntary termination of employment for Good Reason (as defined in the Change of Control Severance Plan) or (iii) an involuntary termination that qualifies for severance under the Ameren Corporation Severance Plan for Ameren Employees (as in effect immediately prior to the Change of Control).

(d)Termination in Anticipation of Change of Control. If a Participant qualifies for benefits as provided in the last sentence of Section 4.1 of the Change of Control Severance Plan, or if a Participant is not a Participant in the Change of Control Severance Plan but is terminated within six (6) months prior to the Change of Control and qualifies for severance benefits under the Company’s general severance plan and the Participant’s termination of employment occurs before December 31, 2016, then the Participant shall receive (i) upon a Change of Control described in Section 9(a) of this Agreement, an immediate cash payout equal to the value of one Share based on the closing price on the New York Stock Exchange on the last trading day prior to the date of the Change of Control multiplied by the sum of the Target Number of Performance Share Units awarded as set forth in Section 1(b) of this Agreement plus the additional Performance Share Units attributable to accrued dividends or (ii) upon a Change of Control described in Section 9(b) of this Agreement, the payout provided for in Section 9(b) of this Agreement.

10.Termination for Cause. Termination of employment for Cause at any time prior to payout of the Shares will require forfeiture of the entire Performance Share Unit Award, with no distribution of any Shares to the Participant.

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11.Nontransferability. Performance Share Units awarded pursuant to this Agreement may not be sold, transferred, pledged, assigned or otherwise alienated or hypothecated (a “Transfer”) other than by will or by the laws of descent and distribution, except as provided in the Plan. If any Transfer, whether voluntary or involuntary, of Performance Share Units is made, or if any attachment, execution, garnishment, or lien will be issued against or placed upon the Performance Share Units, the Participant’s right to such Performance Share Units will be immediately forfeited to the Company, and this Agreement will lapse.

12.Requirements of Law. The granting of Performance Share Units under the Plan will be subject to all applicable laws, rules, and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.

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

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

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

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

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

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

- 7 -

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

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

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

22.Section 409A of the Code. Notwithstanding any other provision of this Award Agreement, if this Award would be considered deferred compensation as defined under Section 409A of the Code and would fail to meet the requirements of Section 409A of the Code, then this Award shall be null and void. The Company makes no representation or covenants that this Award will comply with Section 409A of the Code.

IN WITNESS WHEREOF, the parties have caused this Agreement to be executed effective as of January 1, 2014.

By:	/s/ Mark C. Lindgren
	Vice President, Human Resources of
	Ameren Services Company, on behalf of
	Ameren Corporation
By:
	Participant

- 8 -

EXHIBIT 1

Total Shareholder Return

Total Shareholder Return shall be calculated as follows:

*In practice, dividends will be treated as having been reinvested quarterly.

Peer Group

Following are the peer group companies. In order to be counted in the final calculations, a company must still have a ticker at the end of the performance period, except companies that declare bankruptcy during the performance period will remain in the group and their TSR will be set at a negative 100%.

Company	Ticker	Company	Ticker
ALLIANT ENERGY GROUP	LNT	PEPCO HOLDINGS	POM
CLECO CORPORATION	CNL	PG&E	PCG
CMS ENERGY	CMS	PINNACLE WEST CAPITAL CORP	PNW
CONSOLIDATED EDISON	ED	PORTLAND GENERAL	POR
DTE ENERGY CO	DTE	SCANA CORP.	SCG
EDISON INTERNATIONAL	EIX	SOUTHERN COMPANY	SO
GREAT PLAINS ENERGY INC	GXP	UIL HOLDINGS	UIL
INTEGRYS ENERGY GROUP	TEG	XCEL ENERGY INC	XEL
NISOURCE	NI	WESTAR ENERGY, INC.	WR
NORTHEAST UTILITIES	NU	WISCONSIN ENERGY	WEC

- 9 -

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,
	2014
Earnings available for fixed charges, as defined:
Net income from continuing operations attributable to Ameren Corporation	$	97,216
Income from equity investee	(142		)
Distributed income from equity investee	510
Tax expense based on income	63,947
Fixed charges excluding subsidiary preferred stock dividends tax adjustment (a)	99,948
Earnings available for fixed charges, as defined	$	261,479
Fixed charges, as defined:
Interest expense on short-term and long-term debt  (a)	$	90,669
Estimated interest cost within rental expense	2,134
Amortization of net debt premium, discount, and expenses	5,534
Subsidiary preferred stock dividends	1,611
Adjust subsidiary preferred stock dividends to pretax basis	1,013
Total fixed charges, as defined	$	100,961
Consolidated ratio of earnings to fixed charges	2.59

(a) Includes net interest 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,
	2014
Earnings available for fixed charges, as defined:
Net income	$	48,049
Tax expense based on income	28,928
Fixed charges (a)	57,185
Earnings available for fixed charges, as defined	$	134,162
Fixed charges, as defined:
Interest expense on short-term and long-term debt  (a)	$	54,321
Estimated interest cost within rental expense	1,073
Amortization of net debt premium, discount, and expenses	1,791
Total fixed charges, as defined	$	57,185
Ratio of earnings to fixed charges	2.35
Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends	$	855
Adjustment to pretax basis	515
	$	1,370
Combined fixed charges and preferred stock dividend requirements	$	58,555
Ratio of earnings to combined fixed charges and preferred stock dividend requirements	2.29

(a) Includes net interest 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,
	2014
Earnings available for fixed charges, as defined:
Net income	$	53,719
Tax expense based on income	35,385
Fixed charges (a)	30,776
Earnings available for fixed charges, as defined	$	119,880
Fixed charges, as defined:
Interest expense on short-term and long-term debt (a)	$	26,535
Estimated interest cost within rental expense	1,050
Amortization of net debt premium, discount, and expenses	3,191
Total fixed charges, as defined	$	30,776
Ratio of earnings to fixed charges	3.90
Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends	$	756
Adjustment to pretax basis	498
	$	1,254
Combined fixed charges and preferred stock dividend requirements	$	32,030
Ratio of earnings to combined fixed charges and preferred stock dividend requirements	3.74

(a) Includes net interest 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, Warner L. Baxter, certify that:

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2014 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 12, 2014

 /s/ Warner L. Baxter

Warner L. Baxter

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, 2014 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 12, 2014

 /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, Michael L. Moehn, certify that:

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2014 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 12, 2014

/s/ Michael L. Moehn    

Michael L. Moehn

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, 2014 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 12, 2014

 /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, 2014 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 12, 2014

 /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, 2014 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 12, 2014

 /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, 2014 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 12, 2014

 
/s/ Warner L. Baxter

Warner L. Baxter

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, 2014 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 12, 2014

 /s/ Michael L. Moehn

Michael L. Moehn

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, 2014 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 12, 2014

 /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

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Schedule of Unrecognized Tax Benefits (Detriments)) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Schedule of Unrecognized Tax Benefits (Detriments) [Line Items]
Unrecognized tax benefits (detriments)	$ 92	$ 90
Union Electric Company
Schedule of Unrecognized Tax Benefits (Detriments) [Line Items]
Unrecognized tax benefits (detriments)	32	31
Ameren Illinois Company
Schedule of Unrecognized Tax Benefits (Detriments) [Line Items]
Unrecognized tax benefits (detriments)	$ (1)	$ (1)

XML

Derivative Financial Instruments (Offsetting Derivative Assets and Liabilities) (Details) (Commodity Contract, USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
Offsetting Assets and Liabilities [Line Items]
Gross Amounts Recognized in the Balance Sheet	$ 28	[1]	$ 34	[1]
Derivative Instruments	12		10
Cash Collateral Received/Posted		[2]		[2]
Net Amount	16		24
Gross Amounts Recognized in the Balance Sheet	172	[1]	178	[1]
Derivative Instruments	12		10
Cash Collateral Received/Posted	12	[2]	24	[2]
Net Amount	148		144
Union Electric Company
Offsetting Assets and Liabilities [Line Items]
Gross Amounts Recognized in the Balance Sheet	23	[1]	33	[1]
Derivative Instruments	9		9
Cash Collateral Received/Posted		[2]		[2]
Net Amount	14		24
Gross Amounts Recognized in the Balance Sheet	23	[1]	24	[1]
Derivative Instruments	9		9
Cash Collateral Received/Posted	9	[2]	9	[2]
Net Amount	5		6
Ameren Illinois Company
Offsetting Assets and Liabilities [Line Items]
Gross Amounts Recognized in the Balance Sheet	5		1
Derivative Instruments	3		1
Cash Collateral Received/Posted		[2]		[2]
Net Amount	2
Gross Amounts Recognized in the Balance Sheet	149	[1]	154	[1]
Derivative Instruments	3		1
Cash Collateral Received/Posted	3	[2]	15	[2]
Net Amount	$ 143		$ 138

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

[2] Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current assets” and “Other assets” on the balance sheet.

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Long-Term Debt And Equity Financings Long-Term Debt and Equity Financings (Schedule of Debt Redemptions (Details) (Ameren Illinois Company, USD $)		1 Months Ended
	Mar. 31, 2014	Jan. 31, 2014 Environmental Improvement And Pollution Control Revenue Bonds [Member]	Jan. 31, 2014 Environmental Improvement And Pollution Control Revenue Bonds [Member] Series1993590 Due2023 [Member]		Jan. 31, 2014 Environmental Improvement And Pollution Control Revenue Bonds [Member] Series1994A 570 Due 2024 [Member]		Jan. 31, 2014 Environmental Improvement And Pollution Control Revenue Bonds [Member] Series C11993595 Due2026 [Member]	Jan. 31, 2014 Environmental Improvement And Pollution Control Revenue Bonds [Member] Series C21993570 Due2026 [Member]	Jan. 31, 2014 Environmental Improvement And Pollution Control Revenue Bonds [Member] Series1998A 5 Point 40 Due 2028 [Member]	Jan. 31, 2014 Environmental Improvement And Pollution Control Revenue Bonds [Member] Series1998b540 Due2028 [Member]
Long-Term Debt And Equity Financings [Line Items]
Debt Instrument, Face Amount	$ 1,000,000
Redemptions of Long-term Debt		$ 163,000,000	$ 32,000,000	[1]	$ 36,000,000	[1]	$ 35,000,000	$ 8,000,000	$ 19,000,000	$ 33,000,000

[1] Less than $1 million principal amount of the bonds remain outstanding after redemption

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Callaway Energy Center (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014 mill	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Nuclear Waste Matters [Line Items]
Miscellaneous accounts and notes receivable	$ 201	$ 196
Nuclear Plant [Member]
Nuclear Waste Matters [Line Items]
Number of mills charged for NWF fee	1
Miscellaneous accounts and notes receivable	15	15
Assumed life of plant, in years	40 years
Annual decommissioning costs included in costs of service		$ 7	$ 7	$ 7

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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	3 Months Ended	12 Months Ended	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Union Electric Company	Dec. 31, 2013 Union Electric Company	Mar. 31, 2014 Ameren Illinois Company	Dec. 31, 2012 Ameren Illinois Company
Derivative [Line Items]
Maximum exposure to counterparties related to derivative contracts	$ 14	$ 13	$ 9	$ 12	$ 5	$ 1

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Short-Term Debt And Liquidity Short-Term Debt and Liquidity (Commercial Paper) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Line of Credit Facility [Line Items]
Average Daily Commercial Paper Borrowings Outstanding	$ 539		$ 2
Weighted Average Interest Rate	0.45%		0.80%
Peak Short Term Borrowings	700	[1]	21	[1]
Peak Short Term Borrowings Interest Rate	0.75%		0.85%
Ameren (parent) [Domain]
Line of Credit Facility [Line Items]
Average Daily Commercial Paper Borrowings Outstanding	339		2
Weighted Average Interest Rate	0.45%		0.80%
Peak Short Term Borrowings	452	[1]	21	[1]
Peak Short Term Borrowings Interest Rate	0.75%		0.85%
Union Electric Company
Line of Credit Facility [Line Items]
Average Daily Commercial Paper Borrowings Outstanding	200
Weighted Average Interest Rate	0.45%
Peak Short Term Borrowings	$ 290	[1]		[1]
Peak Short Term Borrowings Interest Rate	0.70%

[1] (a)The timing of peak commercial paper issuances varies by company, and therefore the amounts presented by company might not equal the Ameren Consolidated peak

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Divestiture Transactions and Discontinued Operations (Tables)

3 Months Ended

Mar. 31, 2014

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

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, 2014, and December 31, 2013:

	March 31, 2014		December 31, 2013
Assets of discontinued operations
Cash and cash equivalents	$	—	$	—
Accounts receivable and unbilled revenue	—		5
Materials and supplies	—		5
Property and plant, net	—		142
Accumulated deferred income taxes, net(a)	15		13
Total assets of discontinued operations	$	15	$	165
Liabilities of discontinued operations
Accounts payable and other current obligations	$	2	$	5
Asset retirement obligations(b)	31		40
Total liabilities of discontinued operations	$	33	$	45

(a) Balances primarily consist of deferred income tax assets related to the abandoned Meredosia and Hutsonville energy centers.

(b) Includes AROs associated with the abandoned Meredosia and Hutsonville energy centers of $31 million at March 31, 2014, and December 31, 2013.

for the three months ended March 31, 2014, and 2013:

	Three months
	2014			2013
Operating revenues	$	1		$	264
Operating expenses	(2		)	(415		)	(a)
Operating loss	(1		)	(151		)
Other loss	—			(2		)
Interest charges	—			(11		)
Loss before income taxes	(1		)	(164		)
Income tax expense	—			(35		)
Loss from discontinued operations, net of taxes	$	(1	)	$	(199	)

(a) Included a noncash pretax asset impairment charge of $155 million

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, 2014, at an assumed annual 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	$	4,018		≥2.5	118.8	$	2,272
Ameren Illinois	≥2.0	7.6		3,732	(d)	≥1.5	2.7		203	(e)

(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 $729 million and $454 million at Ameren Missouri and Ameren Illinois, respectively.

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

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

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Retirement Benefits (Summary Of Benefit Plan Costs Incurred) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Pension Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	$ 25	[1]	$ 31	[1]
Pension Benefit [Member] | Union Electric Company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	17		18
Pension Benefit [Member] | Ameren Illinois Company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	8		10
Pension Benefit [Member] | Other
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	0		3
Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	0	[1]	3	[1]
Postretirement Benefits [Member] | Union Electric Company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	1		2
Postretirement Benefits [Member] | Ameren Illinois Company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	(1)		1
Postretirement Benefits [Member] | Other
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	$ 0		$ 0

[1] Includes amounts for Ameren registrants and nonregistrant subsidiaries

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Derivative Financial Instruments (Derivative Instruments With Credit Risk-Related Contingent Features) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
Derivative [Line Items]
Aggregate Fair Value of Derivative Liabilities	$ 136	[1]	$ 145	[1]
Cash Collateral Posted	5		17
Potential Aggregate Amount of Additional Collateral Required	116	[2]	122	[2]
Union Electric Company
Derivative [Line Items]
Aggregate Fair Value of Derivative Liabilities	56	[1]	70	[1]
Cash Collateral Posted	2		2
Potential Aggregate Amount of Additional Collateral Required	51	[2]	67	[2]
Ameren Illinois Company
Derivative [Line Items]
Aggregate Fair Value of Derivative Liabilities	80	[1]	75	[1]
Cash Collateral Posted	3		15
Potential Aggregate Amount of Additional Collateral Required	$ 65	[2]	$ 55	[2]

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

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Divestiture Transactions and Discontinued Operations (Components of Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013		Mar. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset retirement obligations	$ 373		$ 369
Assets of discontinued operations
Cash and cash equivalents					25
Accounts receivable and unbilled revenue			5
Materials and supplies			5
Property and plant, net			142
Accumulated deferred income taxes, net(a)	15	[1]	13	[1]
Total assets of discontinued operations	15		165
Liabilities of discontinued operations
Accounts payable and other current obligations	2		5
Asset retirement obligations(b)	31	[2]	40	[2]
Total liabilities of discontinued operations	33		45
Shutdown Of Meredosia And Hutsonville Energy Centers [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset retirement obligations	$ 31		$ 31

[1] (a)Balances primarily consist of deferred income tax assets related to the abandoned Meredosia and Hutsonville energy centers.

[2] (b)Includes AROs associated with the abandoned Meredosia and Hutsonville energy centers of $31 million at March 31, 2014, and December 31, 2013.

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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, 2014		Mar. 31, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]
External revenues	$ 1,594		$ 1,475
Net income (loss) attributable to Ameren Corporation from continuing operations	97		54
Total assets	21,166			21,042
Assets of discontinued operations (Note 12)	15			165
Union Electric Company
Segment Reporting Information [Line Items]
External revenues	811		789
Intersegment revenues	6		7
Net income (loss) attributable to Ameren Corporation from continuing operations	47		40
Total assets	12,948			12,904
Ameren Illinois Company
Segment Reporting Information [Line Items]
External revenues	774		684
Intersegment revenues
Net income (loss) attributable to Ameren Corporation from continuing operations	53		31
Total assets	7,640			7,454
Other
Segment Reporting Information [Line Items]
External revenues	9		2
Intersegment revenues	1		2
Net income (loss) attributable to Ameren Corporation from continuing operations	(3)		(17)
Total assets	898			752
Intersegment Eliminations
Segment Reporting Information [Line Items]
External revenues
Intersegment revenues	(7)		(9)
Net income (loss) attributable to Ameren Corporation from continuing operations
Total assets	(335)			(233)
Consolidated, Continuing Operations
Segment Reporting Information [Line Items]
External revenues	1,594		1,475
Intersegment revenues
Net income (loss) attributable to Ameren Corporation from continuing operations	97		54
Total assets	$ 21,151	[1]		$ 20,877	[1]

[1] Excludes total assets from discontinued operations of $15 million and $165 million as of March 31, 2014, and December 31, 2013, respectively.

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Retirement Benefits (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014
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	$ 270
Minimum
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	20
Maximum
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	$ 100

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Short-Term Debt And Liquidity Short-Term Debt and Liquidity (Tables)

3 Months Ended

Mar. 31, 2014

Schedule of Commercial paper [Abstract]

Schedule of Short-term Debt [Table Text Block]

The following table summarizes the commercial paper activity and relevant interest rates under Ameren’s (parent) and Ameren Missouri’s commercial paper programs for the three months ended March 31, 2014, and 2013:

	Ameren (parent)			Ameren Missouri			Ameren Consolidated
2014
Average daily commercial paper outstanding	$	339		$	200		$	539
Weighted-average interest rate	0.45		%	0.45		%	0.45		%
Peak commercial paper during period(a)	$	452		$	290		$	700
Peak interest rate	0.75		%	0.70		%	0.75		%
2013
Average daily commercial paper outstanding	$	2		$	—		$	2
Weighted-average interest rate	0.80		%	—		%	0.80		%
Peak commercial paper during period(a)	$	21		$	—		$	21
Peak interest rate	0.85		%	—		%	0.85		%

(a) The timing of peak commercial paper issuances varies by company, and therefore the amounts presented by company might not equal the Ameren Consolidated peak commercial paper issuances for the period.

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Other Income and Expenses (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Other Nonoperating Income (Expense) [Line Items]
Allowance for equity funds used during construction	$ 7	[1]	$ 8	[1]
Interest income on industrial development revenue bonds	7	[1]	7	[1]
Interest and dividend income	2	[1]		[1]
Other	2	[1]		[1]
Total miscellaneous income	18	[1]	15	[1]
Donations	5	[1]	4	[1]
Other	4	[1]	4	[1]
Total miscellaneous expense	9	[1]	8	[1]
Union Electric Company
Other Nonoperating Income (Expense) [Line Items]
Allowance for equity funds used during construction	7		7
Interest income on industrial development revenue bonds	7		7
Total miscellaneous income	14		14
Donations	2		2
Other	2		3
Total miscellaneous expense	4		5
Ameren Illinois Company
Other Nonoperating Income (Expense) [Line Items]
Allowance for equity funds used during construction			1
Interest and dividend income	2
Other	1
Total miscellaneous income	3		1
Donations	3		3
Other	1
Total miscellaneous expense	$ 4		$ 3

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

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Rate And Regulatory Matters (Narrative-Missouri) (Detail) (USD $) In Millions, unless otherwise specified						1 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Union Electric Company	Dec. 31, 2013 Union Electric Company	Mar. 31, 2014 Electric Distribution [Member] Union Electric Company Accounting Authority Order Request [Member]	Feb. 28, 2014 Customer [Domain] Electric Distribution [Member] Union Electric Company	Feb. 13, 2014 Customer [Domain] Electric Distribution [Member] Union Electric Company customer
Rate And Regulatory Matters [Line Items]
Regulatory assets	$ 1,251	$ 1,240	$ 539	$ 534	$ 36
Number of Customers Filed Complaint Case							37
Contested return on equity						9.80%
Customer Requested Rate Decrease						$ 67
Customer Requested Rate on Equity						9.40%

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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, 2014	Mar. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenues	$ 1	$ 264
Operating expenses	(2)	(415)	[1]
Operating loss	(1)	(151)
Other loss		(2)
Interest charges		(11)
Loss before income taxes	(1)	(164)
Income tax expense		(35)
Loss from discontinued operations, net of taxes	(1)	(199)
New Ameren Energy Resources Company, LLC
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

[1] Included a noncash pretax asset 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.

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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, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 9		$ 4
Union Electric Company
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	6	[1]	1	[2]
Ameren Illinois Company
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 3		$ 4

[1] igher priced renewable energy credits.

[2] Less than $1 million.

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Derivative Financial Instruments (Derivative Instruments Carrying Value) (Detail) (Not Designated As Hedging Instrument [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
Derivative [Line Items]
Derivative assets	$ 28	[1]	$ 34	[1]
Derivative liabilities	172	[1]	178	[1]
Fuel Oils | Other Current Assets [Member]
Derivative [Line Items]
Derivative assets	5	[1]	6	[1]
Fuel Oils | Other Assets [Member]
Derivative [Line Items]
Derivative assets	1	[1]	3	[1]
Fuel Oils | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	2	[1]	2	[1]
Fuel Oils | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	2	[1]	1	[1]
Natural Gas | Other Current Assets [Member]
Derivative [Line Items]
Derivative assets	6	[1]	2	[1]
Natural Gas | Other Assets [Member]
Derivative [Line Items]
Derivative assets	1	[1]
Natural Gas | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	20	[1]	32	[1]
Natural Gas | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	17	[1]	25	[1]
Power | Other Current Assets [Member]
Derivative [Line Items]
Derivative assets	15	[1]	23	[1]
Power | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	14	[1]	13	[1]
Power | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	112	[1]	99	[1]
Uranium | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	4	[1]	5	[1]
Uranium | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	1	[1]	1	[1]
Union Electric Company
Derivative [Line Items]
Derivative assets	23	[1]	33	[1]
Derivative liabilities	23	[1]	24	[1]
Union Electric Company | Fuel Oils | Other Current Assets [Member]
Derivative [Line Items]
Derivative assets	5	[1]	6	[1]
Union Electric Company | Fuel Oils | Other Assets [Member]
Derivative [Line Items]
Derivative assets	1	[1]	3	[1]
Union Electric Company | Fuel Oils | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	2	[1]	2	[1]
Union Electric Company | Fuel Oils | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	2	[1]	1	[1]
Union Electric Company | Natural Gas | Other Current Assets [Member]
Derivative [Line Items]
Derivative assets	1	[1]	1	[1]
Union Electric Company | Natural Gas | Other Assets [Member]
Derivative [Line Items]
Derivative assets	1	[1]
Union Electric Company | Natural Gas | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	4	[1]	5	[1]
Union Electric Company | Natural Gas | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	4	[1]	6	[1]
Union Electric Company | Power | Other Current Assets [Member]
Derivative [Line Items]
Derivative assets	15	[1]	23	[1]
Union Electric Company | Power | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	6	[1]	4	[1]
Union Electric Company | Uranium | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	4	[1]	5	[1]
Union Electric Company | Uranium | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	1	[1]	1	[1]
Ameren Illinois Company
Derivative [Line Items]
Derivative assets	5	[1]	1	[1]
Derivative liabilities	149	[1]	154	[1]
Ameren Illinois Company | Natural Gas | Other Current Assets [Member]
Derivative [Line Items]
Derivative assets	5	[1]	1	[1]
Ameren Illinois Company | Natural Gas | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	16	[1]	27	[1]
Ameren Illinois Company | Natural Gas | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	13	[1]	19	[1]
Ameren Illinois Company | Power | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	8	[1]	9	[1]
Ameren Illinois Company | Power | Other Deferred Credits And Liabilities [Member]
Derivative [Line Items]
Derivative liabilities	$ 112	[1]	$ 99	[1]

[1] Includes derivatives subject to regulatory deferral.

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Commitments And Contingencies (Environmental Matters) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Minimum
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	$ 275
Maximum
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	350
Former Coal Tar Distillery | Union Electric Company
Loss Contingencies [Line Items]
Range of possible loss, minimum	2.0
Range of possible loss maximum	5.0
Accrual for environmental loss contingencies	2.0
Former Coal Ash Landfill | Ameren Illinois Company
Loss Contingencies [Line Items]
Range of possible loss, minimum	0.5
Range of possible loss maximum	6.0
Accrual for environmental loss contingencies	0.5
Manufactured Gas Plant
Loss Contingencies [Line Items]
Range of possible loss, minimum	269.0
Range of possible loss maximum	345.0
Accrual for environmental loss contingencies	269.0	[1]
Manufactured Gas Plant | Union Electric Company
Loss Contingencies [Line Items]
Number of remediation sites	1
Range of possible loss, minimum	3.0
Range of possible loss maximum	4.0
Accrual for environmental loss contingencies	3.0	[1]
Manufactured Gas Plant | Ameren Illinois Company
Loss Contingencies [Line Items]
Number of remediation sites	44
Range of possible loss, minimum	266.0
Range of possible loss maximum	341.0
Accrual for environmental loss contingencies	266.0	[1]
Other Environmental | Ameren Illinois Company
Loss Contingencies [Line Items]
Accrual for environmental loss contingencies	0.8
Sauget Area Two | Union Electric Company
Loss Contingencies [Line Items]
Range of possible loss, minimum	1.0
Range of possible loss maximum	2.5
Loss Contingency, Loss in Period	0.7
Accrual for environmental loss contingencies	1.0
Substation in St Charles, Missouri | Union Electric Company
Loss Contingencies [Line Items]
Range of possible loss, minimum	1.6
Range of possible loss maximum	4.5
Accrual for environmental loss contingencies	$ 1.6

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

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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, 2014	Mar. 31, 2013
Fuel Oils
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ 5	$ 5
Included in regulatory assets/liabilities	(2)
Purchases		1
Settlements	(2)	(1)
Ending balance	1	5
Change in unrealized gains (losses) related to assets/liabilities held at period end	(1)
Uranium
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(6)	(2)
Settlements	1
Ending balance	(5)	(2)
Change in unrealized gains (losses) related to assets/liabilities held at period end
Natural Gas
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	0	0
Included in regulatory assets/liabilities		1
Purchases	(2)	1
Settlements	2
Ending balance	0	2
Change in unrealized gains (losses) related to assets/liabilities held at period end
Power
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(89)	(100)
Included in regulatory assets/liabilities	(17)	19
Settlements	(5)	3
Transfers into Level 3		(2)
Transfer out of Level 3	1	1
Ending balance	(110)	(79)
Change in unrealized gains (losses) related to assets/liabilities held at period end	(15)	11
Union Electric Company | Fuel Oils
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	5	5
Included in regulatory assets/liabilities	(2)
Purchases		1
Settlements	(2)	(1)
Ending balance	1	5
Change in unrealized gains (losses) related to assets/liabilities held at period end	(1)
Union Electric Company | Uranium
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(6)	(2)
Settlements	1
Ending balance	(5)	(2)
Change in unrealized gains (losses) related to assets/liabilities held at period end
Union Electric Company | Natural Gas
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance
Included in regulatory assets/liabilities
Purchases
Ending balance
Change in unrealized gains (losses) related to assets/liabilities held at period end
Union Electric Company | Power
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	19	11
Included in regulatory assets/liabilities	(5)	5
Settlements	(5)	(13)
Transfers into Level 3		(2)
Transfer out of Level 3	1	1
Ending balance	10	2
Change in unrealized gains (losses) related to assets/liabilities held at period end	(1)	(3)
Ameren Illinois Company | Natural Gas
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	0	0
Included in regulatory assets/liabilities		1
Purchases	(2)	1
Settlements	2
Ending balance	0	2
Change in unrealized gains (losses) related to assets/liabilities held at period end
Ameren Illinois Company | Power
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(108)	(111)
Included in regulatory assets/liabilities	(12)	14
Settlements		16
Transfers into Level 3
Transfer out of Level 3
Ending balance	(120)	(81)
Change in unrealized gains (losses) related to assets/liabilities held at period end	$ (14)	$ 14

XML

Long-Term Debt And Equity Financings (Narrative) (Detail) (USD $)	3 Months Ended					1 Months Ended
	Mar. 31, 2014	Mar. 31, 2014 Ameren Missouri And Ameren Illinois [Member]	Mar. 31, 2014 Ameren Illinois Company	Mar. 31, 2014 Ameren Illinois Company Federal Energy Regulatory Commission Restriction [Member]	Mar. 31, 2014 Ameren Illinois Company Minimum Federal Energy Regulatory Commission Restriction [Member]	Jan. 31, 2014 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company	Apr. 30, 2014 Subsequent Event [Member] Secured Debt [Member] Senior Secured Notes, 3.50%, Due 2024 [Member] Union Electric Company	May 31, 2014 Subsequent Event [Member] Secured Debt [Member] Senior Secured Notes550 Due2014 [Member] Union Electric Company	May 15, 2014 Subsequent Event [Member] Secured Debt [Member] Senior Secured Notes550 Due2014 [Member] Union Electric Company
Long-Term Debt And Equity Financings [Line Items]
Debt Instrument, Face Amount			$ 1,000,000				$ 350,000,000
Redemptions of Long-term Debt						163,000,000		104,000,000
Debt Instrument, Interest Rate, Stated Percentage							3.50%		5.50%
Assumed interest rate		6.00%
Dividend rate		7.00%
Excess in indebtedness upon default of maturity	25,000,000
Common stock equity to total capitalization				55.00%	30.00%
Proceeds from Issuance of Secured Debt							$ 348,000,000

XML

Rate And Regulatory Matters

3 Months Ended

Mar. 31, 2014

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

Accounting Authority Order

In July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren Missouri to defer fixed costs totaling $36 million that were not previously 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. In November 2013, the MoPSC issued an order approving Ameren Missouri’s request for an accounting authority order, which will allow Ameren Missouri to seek recovery of these fixed costs in a future electric rate case. Ameren Missouri will seek to recover these fixed costs in its next electric rate case, which it will file by July 15, 2014. In February 2014, MIEC and MoOPC filed appeals of the accounting authority order to the Missouri Court of Appeals, Western District.

Earnings Complaint and Rate Shift Complaint Cases

In February 2014, Ameren Missouri’s largest customer, Noranda, and 37 residential customers filed an earnings complaint case and a rate shift complaint case with the MoPSC. In the earnings complaint case, Noranda and the residential customers asserted that Ameren Missouri’s electric service business is earning more than the 9.8% return on equity authorized in the MoPSC's December 2012 electric rate order and requested that the MoPSC approve a $67 million reduction to Ameren Missouri’s annual revenue requirement. Included in Noranda’s request is a reduction of Ameren Missouri’s authorized return on equity to 9.4%. The rate shift complaint case seeks to reduce Noranda’s electricity cost with an offsetting increase in electricity cost for Ameren Missouri’s other customers. While the rate shift proposal is revenue neutral to Ameren Missouri, Ameren Missouri does not believe that the proposed reduction to Noranda’s electric rates, which are significantly below Ameren Missouri’s cost of service, is appropriate or in the best interests of Ameren Missouri’s other electric customers. The MoOPC and MIEC have intervened in the earnings complaint case.

While the MoPSC has no time requirement by which it must issue an order in these cases, it has adopted procedural schedules that would render a decision in the rate shift case by August 6, 2014, and in the earnings complaint case by September 26, 2014. Ameren Missouri does not believe that a reduction in electric service rates is justified and will file testimony that supports that position, which is consistent with Ameren Missouri’s expected July 2014 rate case filing. The MoPSC has 11 months from when Ameren Missouri files its request to issue an order.

Illinois

IEIMA

Under the provisions of the IEIMA, Ameren Illinois’ electric delivery service rates are subject to an annual revenue requirement reconciliation to its actual costs. Throughout each year, Ameren Illinois records a regulatory asset or a regulatory liability and a corresponding increase or decrease to operating revenues for any differences between the revenue requirement in effect for that year and its estimate of the probable increase or decrease in the revenue requirement expected to ultimately be approved by the ICC based on that year's actual costs incurred. As of March 31, 2014, Ameren Illinois had recorded a regulatory asset of $24 million to reflect its expected 2014 revenue requirement reconciliation adjustment, with interest.

In September 2012 and December 2012, the ICC issued orders in Ameren Illinois’ IEIMA performance-based formula rate filings. Ameren Illinois appealed both orders to the Appellate Court of the Fourth District of Illinois. The primary issues Ameren Illinois appealed were the rate treatment of accumulated deferred income taxes and vacation obligations as well as the calculation of Ameren Illinois’ capital structure. In December 2013, the appellate court rendered its decision upholding the ICC’s September and December 2012 orders. Ameren Illinois filed an appeal to the Illinois Supreme Court in March 2014.

In December 2013, the ICC issued an order in Ameren Illinois' annual update filing, which was based on 2012 recoverable costs and expected net plant additions for 2013. The ICC order established rates for 2014. In February 2014, Ameren Illinois filed an appeal to the Appellate Court of the Fourth District of Illinois regarding the calculation of its capital structure and the rate treatment of accumulated deferred income taxes related to the transfer of former Ameren Missouri assets in Illinois to Ameren Illinois.

In April 2014, Ameren Illinois filed with the ICC its annual electric delivery service formula rate update to establish the revenue requirement used to set rates for 2015. Pending ICC approval, Ameren Illinois’ update filing will result in a $206 million increase in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2015. This update reflects an increase to the annual formula rate based on 2013 actual costs and expected net plant additions for 2014; an increase to include the annual reconciliation of the revenue requirement in effect for 2013 to the actual costs incurred in that year; and an increase resulting from the conclusion of a refund to customers in 2014 for the 2012 revenue requirement reconciliation. An ICC decision on this April 2014 filing is expected by December 2014.

2013 Natural Gas Delivery Service Rate Case

In December 2013, the ICC issued a rate order that approved an increase in revenues for natural gas delivery service of $32 million. The revenue increase was based on a 9.1% return on equity, a capital structure composed of 51.7% common equity, and a rate base of $1.1 billion. The rate order was based on a 2014 future test year. The rate changes became effective January 1, 2014. In March 2014, Ameren Illinois filed an appeal of the allowed return on equity included in the ICC's order with the Appellate Court of the Fourth District of Illinois. Ameren Illinois sought a 10.4% return on equity in this rate case.

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 a settlement with four of its nine wholesale customers, which have been approved by FERC and refunds have been issued. The impasse with the remaining five wholesale customers is awaiting final FERC action. In November 2012, a FERC administrative law judge issued an initial decision, which is now pending before FERC. The timing of a decision from FERC is uncertain and subsequent appeals are possible. In accordance with the administrative law judge's initial decision, Ameren and Ameren Illinois have both included on their balance sheets in “Current regulatory liabilities” an estimate of $14 million and $13 million as of March 31, 2014, and December 31, 2013, respectively, for the refund due to the remaining wholesale customers relating to billings for the period from March 2011 through March 2014.

Ameren Illinois Electric Transmission Rate Refund

In July 2012, FERC issued an order concluding that Ameren Illinois improperly included acquisition premiums, primarily goodwill, in determining the common equity used in its electric transmission formula rate, and thereby inappropriately recovered a higher amount 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 a 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.

Ameren Illinois submitted a refund report in November 2012 and concluded that no refund was warranted. Several wholesale customers filed a protest with FERC regarding Ameren's conclusion that no refund was warranted. In June 2013, FERC issued an order that rejected Ameren Illinois' November 2012 refund report and provided guidance as to the filing of a new refund report. In July 2013, Ameren Illinois filed a revised refund report based on the guidance provided in the June 2013 order, as well as a request for a rehearing of that order. Ameren Illinois' July 2013 refund report also concluded that no refund was warranted. Ameren Illinois estimated the maximum pretax charge to earnings for this possible refund obligation through December 31, 2014 would be $19 million, before interest charges. 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.

FERC Complaint Case

In November 2013, a customer group filed a complaint case with FERC seeking a reduction in the allowed return on common equity to 9.15%, as well as a limit on the common equity ratio, under the MISO tariff. Currently, the FERC-allowed return on common equity for MISO transmission owners is 12.38%. This complaint case could result in a reduction to Ameren Illinois' and ATXI's allowed return on common equity. That reduction could also result in a refund for transmission service revenues earned after the filing of the complaint case in November 2013. FERC has not issued an order in this case, and it is under no deadline to do so. Ameren is not able to predict if or how FERC will rule on this complaint case.

Ameren Missouri Power Purchase Agreement with Entergy

Beginning in 2005, FERC issued a series of orders addressing a complaint filed in 2001 by the Louisiana Public Service Commission against Entergy and certain of its affiliates. The complaint alleged unjust and unreasonable cost allocations. As a result of the FERC orders, Entergy began billing Ameren Missouri in 2007 for additional charges under a 165-megawatt power purchase agreement, which expired August 31, 2009. In May 2012, FERC issued an order stating that Entergy should not have included additional charges to Ameren Missouri under the power purchase agreement. Pursuant to the order, in June 2012, Entergy paid Ameren Missouri $31 million. In July 2012, Entergy filed an appeal of FERC's January 2010 and May 2012 orders to the United States Court of Appeals for the District of Columbia Circuit, which was subsequently dismissed on a procedural issue. In November 2013, Entergy refiled the appeal of FERC's May 2012 order with the United States Court of Appeals for the District of Columbia Circuit. Ameren is not able to predict when or how the court will rule on Entergy's appeal.

The Louisiana Public Service Commission appealed FERC’s orders regarding Louisiana Public Service Commission’s complaint against Entergy Services, Inc. to the United States Court of Appeals for the District of Columbia Circuit. In April 2008, that court ordered further FERC proceedings regarding Louisiana Public Service Commission’s complaint. The court ordered FERC to explain its previous denial of retroactive refunds and the implementation of prospective charges. FERC’s decision on remand of the retroactive impact of these issues could have a financial impact on Ameren Missouri. Ameren Missouri is unable to predict when or how FERC will respond to the court’s decisions. Ameren Missouri estimates that it could incur an additional expense of up to $25 million if FERC orders retroactive application for the years 2001 to 2005. Ameren Missouri believes that the likelihood of incurring any expense is not probable, and therefore no liability has been recorded as of March 31, 2014.

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.

Ameren Missouri estimated the total cost required to obtain a small modular reactor COL to be $80 million to $100 million. As of March 31, 2014, Ameren Missouri had capitalized investments of $69 million for the development of a new nuclear energy center. Ameren Missouri is currently evaluating all potential nuclear technologies in order to maintain an option for nuclear power in the future.

All of Ameren Missouri's capitalized investments for the development of a new nuclear energy center will remain capitalized while management pursues options to maximize the value of its investment. If efforts to license additional nuclear generation are 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.

XML

Fair Value Measurements (Schedule Of Transfers Between Fair Value Hierarchy Levels) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Derivative [Line Items]
Net fair value of Level 3 transfers	$ 1	$ (1)
Power
Derivative [Line Items]
Assets Transfers into Level 3		2
Assets Transfers out of Level 3	1	1
Power | Transfer Into/Out of Level 2
Derivative [Line Items]
Assets Transfers into Level 3		(2)
Assets Transfers out of Level 3	1	1
Union Electric Company
Derivative [Line Items]
Net fair value of Level 3 transfers	1	(1)
Union Electric Company | Power
Derivative [Line Items]
Assets Transfers into Level 3		2
Assets Transfers out of Level 3	1	1
Union Electric Company | Power | Transfer Into/Out of Level 2
Derivative [Line Items]
Assets Transfers into Level 3		(2)
Assets Transfers out of Level 3	1	1
Ameren Illinois Company | Power
Derivative [Line Items]
Assets Transfers into Level 3
Assets Transfers out of Level 3

XML

Rate And Regulatory Matters (Narrative-Illinois) (Detail) (USD $)					12 Months Ended		3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Ameren Illinois Company	Dec. 31, 2013 Ameren Illinois Company	Dec. 31, 2013 Ameren Illinois Company Gas Distribution [Member] Final Rate Order [Member]	Dec. 31, 2013 Ameren Illinois Company Gas Distribution [Member] Rate order appeal [Member]	Mar. 31, 2014 Ieima [Member] Ameren Illinois Company Electric Distribution [Member] IEMA Revenue Requirement Reconciliation [Member]	Mar. 31, 2014 Pending Ferc Case [Member] Midwest Independent Transmission System Operator, Inc [Member]
Rate And Regulatory Matters [Line Items]
Regulatory assets	$ 1,251,000,000	$ 1,240,000,000	$ 706,000,000	$ 701,000,000			$ 24,000,000
Requested rate decrease, amount							206,000,000
Authorized Increase in Revenue from Utility Service					32,000,000
Rate Of Return On Common Equity					9.10%	10.40%		12.38%
Percent Of Capital Structure Composed Of Equity					51.70%
Rate Base					$ 1,100,000,000

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Valuation Techniques

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 as of March 31, 2014:

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
Level 3 Derivative asset and liability - commodity contracts(a):
Ameren	Fuel oils	$	5	$	(4	)	Option model	Volatilities(%)(b)	13 - 34	16
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.25 - 0.99	0.63
	Natural gas	1		(1		)	Option model	Volatilities(%)(b)	27 - 102	40
								Nodal basis($/mmbtu)(c)	(0.3) - (0.2)	(0.2)
							Discounted cash flow	Nodal basis($/mmbtu)(c)	(0.2) - (0.1)	(0.1)
								Counterparty credit risk(%)(c)(d)	0.27 - 5	1
								Ameren Missouri credit risk(%)(c)(d)	0.43	(e)
	Power(f)	14		(124		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	27 - 57	33
								Estimated auction price for FTRs($/MW)(b)	(1,109) - 2,981	474
								Nodal basis($/MWh)(c)	(6) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	0.35	(e)
								Ameren Missouri and Ameren Illinois credit risk(%)(c)(d)	0.43	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 6	5
								Escalation rate(%)(b)(g)	2 - 3	3
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6
	Uranium	—		(5		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	34 - 40	35
Ameren Missouri	Fuel oils	$	5	$	(4	)	Option model	Volatilities(%)(b)	13 - 34	16
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.25 - 0.99	0.63
	Natural gas	1		(1		)	Option model	Volatilities(%)(b)	27 - 102	40
								Nodal basis($/mmbtu)(c)	(0.3) - (0.2)	(0.2)
							Discounted cash flow	Nodal basis($/mmbtu)(c)	(0.2) - (0.1)	(0.1)
								Counterparty credit risk(%)(c)(d)	0.27 - 5	1
								Ameren Missouri credit risk(%)(c)(d)	0.43	(e)
	Power(f)	14		(4		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	30 - 57	45
								Estimated auction price for FTRs($/MW)(b)	(1,109) - 2,981	474
								Nodal basis($/MWh)(c)	(3) - (1)	(2)
								Counterparty credit risk(%)(c)(d)	0.35	(e)
								Ameren Missouri credit risk(%)(c)(d)	0.43	(e)
	Uranium	—		(5		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	34 - 40	35
Ameren Illinois	Power(f)	$	—	$	(120	)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b)	27 - 40	32
								Nodal basis($/MWh)(b)	(6) - (1)	(3)
								Ameren Illinois credit risk(%)(c)(d)	0.43	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 6	5
								Escalation rate(%)(b)(g)	2 - 3	3
							Contract price allocation	Estimated renewable energy credit costs($/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 applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances.

(e) Not applicable.

(f) Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2018. Valuations beyond 2018 use fundamentally modeled pricing by month for peak and off-peak demand.

(g) Escalation rate applies to power prices 2026 and beyond.

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 as of December 31, 2013:

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
Level 3 Derivative asset and liability – commodity contracts(a):
Ameren	Fuel oils	$	8	$	(3	)	Option model	Volatilities(%)(b)	10 - 35	16
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.26 - 2	1
	Power(e)	21		(110		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	25 - 51	32
								Estimated auction price for FTRs($/MW)(b)	(1,594) - 945	305
								Nodal basis($/MWh)(c)	(3) - (1)	(2)
								Counterparty credit risk(%)(c)(d)	0.39 - 0.50	0.42
								Ameren Missouri and Ameren Illinois credit risk(%)(c)(d)	2	(f)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 5	5
								Escalation rate(%)(b)(g)	3 - 4	4
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6
	Uranium	—		(6		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	34 - 41	36
Ameren Missouri	Fuel oils	$	8	$	(3	)	Option model	Volatilities(%)(b)	10 - 35	16
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.26 - 2	1
	Power(e)	21		(2		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	25 - 51	40
								Estimated auction price for FTRs($/MW)(b)	(1,594) - 945	305
								Nodal basis($/MWh)(c)	(3) - (1)	(2)
								Counterparty credit risk(%)(c)(d)	0.39 - 0.50	0.42
								Ameren Missouri credit risk(%)(c)(d)	2	(f)
	Uranium	—		(6		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	34 - 41	36
Ameren Illinois	Power(e)	$	—	$	(108	)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b)	27 - 36	30
								Nodal basis($/MWh)(b)	(4) - 0	(2)
								Ameren Illinois credit risk(%)(c)(d)	2	(f)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 5	5
								Escalation rate(%)(b)(g)	3 - 4	4
							Contract price allocation	Estimated renewable energy credit costs($/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 applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances.

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

(f)

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, 2014:

		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	$	1	$	—	$	5	$	6
	Natural gas	—		6		1		7
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	1	$	7	$	20	$	28
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	327		—		—		327
	Debt securities:
	Corporate bonds	—		61		—		61
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		94		—		94
	Asset-backed securities	—		14		—		14
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	329	$	172	$	—	$	501	(b)
	Total Ameren	$	330	$	179	$	20	$	529
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	1	$	—	$	5	$	6
	Natural gas	—		1		1		2
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	1	$	2	$	20	$	23
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	327		—		—		327
	Debt securities:
	Corporate bonds	—		61		—		61
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		94		—		94
	Asset-backed securities	—		14		—		14
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	329	$	172	$	—	$	501	(b)
	Total Ameren Missouri	$	330	$	174	$	20	$	524
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	—	$	5	$	—	$	5
Liabilities:
Ameren	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	—	$	—	$	4	$	4
	Natural gas	2		34		1		37
	Power	—		2		124		126
	Uranium	—		—		5		5
	Total Ameren	$	2	$	36	$	134	$	172
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	—	$	—	$	4	$	4
	Natural gas	2		5		1		8
	Power	—		2		4		6
	Uranium	—		—		5		5
	Total Ameren Missouri	$	2	$	7	$	14	$	23
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	29	$	—	$	29
	Power	—		—		120		120
	Total Ameren Illinois	$	—	$	29	$	120	$	149

(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 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, 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	$	1	$	—	$	8	$	9
	Natural gas	—		2		—		2
	Power	—		2		21		23
	Total derivative assets - commodity contracts	$	1	$	4	$	29	$	34
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	3	$	—	$	—	$	3
	Equity securities:
	U.S. large capitalization	332		—		—		332
	Debt securities:
	Corporate bonds	—		52		—		52
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		94		—		94
	Asset-backed securities	—		10		—		10
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	335	$	159	$	—	$	494
	Total Ameren	$	336	$	163	$	29	$	528
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	1	$	—	$	8	$	9
	Natural gas	—		1		—		1
	Power	—		2		21		23
	Total derivative assets - commodity contracts	$	1	$	3	$	29	$	33
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	3	$	—	$	—	$	3
	Equity securities:
	U.S. large capitalization	332		—		—		332
	Debt securities:
	Corporate bonds	—		52		—		52
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		94		—		94
	Asset-backed securities	—		10		—		10
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	335	$	159	$	—	$	494
	Total Ameren Missouri	$	336	$	162	$	29	$	527
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	—	$	1	$	—	$	1
Liabilities:
Ameren	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	—	$	—	$	3	$	3
	Natural gas	3		54		—		57
	Power	—		2		110		112
	Uranium	—		—		6		6
	Total Ameren	$	3	$	56	$	119	$	178
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	—	$	—	$	3	$	3
	Natural gas	3		8		—		11
	Power	—		2		2		4
	Uranium	—		—		6		6
	Total Ameren Missouri	$	3	$	10	$	11	$	24
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	46	$	—	$	46
	Power	—		—		108		108
	Total Ameren Illinois	$	—	$	46	$	108	$	154

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

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, 2014:

		Net derivative commodity contracts
Three Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2014	$	5		$	(a)		$	5
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(2	)		(a)			(2	)
Settlements		(2	)		(a)			(2	)
Ending balance at March 31, 2014	$	1		$	(a)		$	1
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2014	$	(1	)	$	(a)		$	(1	)
Natural gas:
Beginning balance at January 1, 2014	$	—		$	—		$	—
Purchases		—			(2	)		(2	)
Settlements		—			2			2
Ending balance at March 31, 2014	$	—		$	—		$	—
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2014	$	—		$	—		$	—
Power:
Beginning balance at January 1, 2014	$	19		$	(108	)	$	(89	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(5	)		(12	)		(17	)
Settlements		(5	)		—			(5	)
Transfers out of Level 3		1			—			1
Ending balance at March 31, 2014	$	10		$	(120	)	$	(110	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2014	$	(1	)	$	(14	)	$	(15	)
Uranium:
Beginning balance at January 1, 2014	$	(6	)	$	(a)		$	(6	)
Settlements		1			(a)			1
Ending balance at March 31, 2014	$	(5	)	$	(a)		$	(5	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2014	$	—		$	(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, 2013:

		Net derivative commodity contracts
Three Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2013	$	5		$	(a)		$	5
Purchases		1			(a)			1
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
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
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	)
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.

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, 2014, and 2013:

	Three Months
	2014						2013
Derivative commodity contracts	Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri			Ameren Illinois		Ameren
Transfers into Level 3 / Transfers out of Level 2 - Power	$	—	$	—	$	—	$	(2	)	$	—	$	(2	)
Transfers out of Level 3 / Transfers into Level 2 - Power	1		—		1		1			—		1
Net fair value of Level 3 transfers	$	1	$	—	$	1	$	(1	)	$	—	$	(1	)

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, capital lease obligations and preferred stock at March 31, 2014, and December 31, 2013:

	March 31, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:(a)
Long-term debt and capital lease obligations (including current portion)	$	5,874	$	6,530	$	6,038	$	6,584
Preferred stock	142		119		142		118
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	3,758	$	4,200	$	3,757	$	4,124
Preferred stock	80		71		80		71
Ameren Illinois:
Long-term debt (including current portion)	$	1,692	$	1,903	$	1,856	$	2,028
Preferred stock	62		48		62		47

(a) Preferred stock is recorded in “Noncontrolling Interests” on the consolidated balance sheet.

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Derivative Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2014

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 for derivative assets and liabilities as of March 31, 2014, and December 31, 2013. As of March 31, 2014, these contracts ran through October 2016, October 2019, May 2032, and October 2016 for fuel oils, natural gas, power, and uranium, respectively.

	Quantity (in millions, except as indicated)
	2014			2013
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)(a)	53	(b)	53	66	(b)	66
Natural gas (in mmbtu)	28	109	137	28	108	136
Power (in megawatthours)	2	11	13	3	11	14
Uranium (pounds in thousands)	827	(b)	827	796	(b)	796

(a) Fuel oils consist of ultra-low-sulfur diesel, on-highway diesel, and crude oil.

(b) Not applicable.

Derivative Instruments Carrying Value

The following table presents the carrying value and balance sheet location of all derivative instruments as of March 31, 2014, and December 31, 2013:

	Balance Sheet Location	Ameren Missouri		Ameren Illinois		Ameren
2014
Derivative assets not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current assets	$	5	$	—	$	5
	Other assets	1		—		1
Natural gas	Other current assets	1		5		6
	Other assets	1		—		1
Power	Other current assets	15		—		15
	Total assets	$	23	$	5	$	28
Derivative liabilities not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current liabilities	$	2	$	—	$	2
	Other deferred credits and liabilities	2		—		2
Natural gas	Other current liabilities	4		16		20
	Other deferred credits and liabilities	4		13		17
Power	Other current liabilities	6		8		14
	Other deferred credits and liabilities	—		112		112
Uranium	Other current liabilities	4		—		4
	Other deferred credits and liabilities	1		—		1
	Total liabilities	$	23	$	149	$	172
2013
Derivative assets not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current assets	$	6	$	—	$	6
	Other assets	3		—		3
Natural gas	Other current assets	1		1		2
Power	Other current assets	23		—		23
	Total assets	$	33	$	1	$	34
Derivative liabilities not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current liabilities	$	2	$	—	$	2
	Other deferred credits and liabilities	1		—		1
Natural gas	Other current liabilities	5		27		32
	Other deferred credits and liabilities	6		19		25
Power	Other current liabilities	4		9		13
	Other deferred credits and liabilities	—		99		99
Uranium	Other current liabilities	5		—		5
	Other deferred credits and liabilities	1		—		1
	Total liabilities	$	24	$	154	$	178

(a) Includes derivatives subject to regulatory deferral.

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 deferred as regulatory assets or regulatory liabilities as of March 31, 2014, and December 31, 2013:

	Ameren Missouri			Ameren Illinois			Ameren
2014
Cumulative gains (losses) deferred as regulatory liabilities or assets:
Fuel oils derivative contracts(a)	$	—		$	—		$	—
Natural gas derivative contracts(b)	(6		)	(24		)	(30		)
Power derivative contracts(c)	9			(120		)	(111		)
Uranium derivative contracts(d)	(5		)	—			(5		)
2013
Cumulative gains (losses) deferred as regulatory liabilities or assets:
Fuel oils derivative contracts	$	2		$	—		$	2
Natural gas derivative contracts	(10		)	(45		)	(55		)
Power derivative contracts	19			(108		)	(89		)
Uranium derivative contracts	(6		)	—			(6		)

(a) Represents net gains (losses) on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through December 2016 as of March 31, 2014. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014.

(b) Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2019 at Ameren and Ameren Missouri and through October 2017 at Ameren Illinois, in each case as of March 31, 2014. 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, 2014. Current losses deferred as regulatory assets include $20 million, $4 million, and $16 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2014.

(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, 2014. Current gains deferred as regulatory liabilities include $15 million and $15 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014. Current losses deferred as regulatory assets include $14 million, $6 million, and $8 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2014.

(d) Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through December 2016, as of March 31, 2014. Current losses deferred as regulatory assets include $4 million and $4 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014.

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, 2014, and December 31, 2013:

			Gross Amounts Not Offset in the Balance Sheet
Commodity Contracts Eligible to be Offset	Gross Amounts Recognized in the Balance Sheet		Derivative Instruments		Cash Collateral Received/Posted(a)		Net Amount
2014
Assets:
Ameren Missouri	$	23	$	9	$	—	$	14
Ameren Illinois	5		3		—		2
Ameren	$	28	$	12	$	—	$	16
Liabilities:
Ameren Missouri	$	23	$	9	$	9	$	5
Ameren Illinois	149		3		3		143
Ameren	$	172	$	12	$	12	$	148
2013
Assets:
Ameren Missouri	$	33	$	9	$	—	$	24
Ameren Illinois	1		1		—		—
Ameren	$	34	$	10	$	—	$	24
Liabilities:
Ameren Missouri	$	24	$	9	$	9	$	6
Ameren Illinois	154		1		15		138
Ameren	$	178	$	10	$	24	$	144

(a) Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current assets” and “Other assets” on the balance sheet.

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, 2014, or December 31, 2013, respectively, 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)
2014
Ameren Missouri	$	56	$	2	$	51
Ameren Illinois	80		3		65
Ameren	$	136	$	5	$	116
2013
Ameren Missouri	$	70	$	2	$	67
Ameren Illinois	75		15		55
Ameren	$	145	$	17	$	122

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

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Derivative Financial Instruments (Potential Loss On Counterparty Exposures) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	$ 5	$ 6
Union Electric Company
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	3	6
Ameren Illinois Company
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	$ 2

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Rate And Regulatory Matters (Narrative-Federal) (Detail) (USD $) In Millions, unless otherwise specified													1 Months Ended			12 Months Ended		3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Ameren Illinois Company	Dec. 31, 2013 Ameren Illinois Company	Mar. 31, 2014 Ameren Illinois Company Pending Ferc Case [Member] Maximum	Mar. 31, 2014 Union Electric Company	Dec. 31, 2013 Union Electric Company	Dec. 31, 2013 Union Electric Company New Nuclear Energy Center COL [Member]	Dec. 31, 2013 Union Electric Company New Nuclear Energy Center COL [Member] Minimum	Dec. 31, 2013 Union Electric Company New Nuclear Energy Center COL [Member] Maximum	Mar. 31, 2014 Wholesale Distribution Rate Case [Member]	Dec. 31, 2013 Wholesale Distribution Rate Case [Member]	Jan. 31, 2011 Wholesale Distribution Rate Case [Member] Ameren Illinois Company appraiser	Mar. 31, 2014 Wholesale Distribution Rate Case [Member] Ameren Illinois Company	Dec. 31, 2013 Wholesale Distribution Rate Case [Member] Ameren Illinois Company	Dec. 31, 2012 Entergy Refund [Member] Union Electric Company	Mar. 31, 2014 Entergy Refund [Member] Union Electric Company	Mar. 31, 2014 Midwest Independent Transmission System Operator, Inc [Member] Pending Ferc Case [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	$ 248	$ 216	$ 201	$ 159		$ 47	$ 57				$ 14	$ 13		$ 14	$ 13
Customer Requested Rate on Equity																		9.15%
Rate Of Return On Common Equity																		12.38%
Proceeds from Legal Settlements																31
Range of possible loss, minimum					19												25
Investments in Power and Distribution Projects								$ 69	$ 80	$ 100

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2014

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, 2014, and 2013. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K, and the money pool arrangements discussed in Note 3 - Short-term Debt and Liquidity of this report.

				Three Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2014	$	(b)	$	(a)
agreements with Ameren Illinois		2013		1		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2014		5		(b)
rent and facility services		2013		5		(b)
Total Operating Revenues		2014	$	5	$	(b)
		2013		6		(b)
Ameren Illinois power supply	Purchased Power	2014	$	(a)	$	(b)
agreements with Ameren Missouri		2013		(a)		1
Ameren Illinois transmission	Purchased Power	2014		(a)		1
services with ATXI		2013		(a)		1
Total Purchased Power		2014	$	(a)	$	1
		2013		(a)		2
Ameren Services support services	Other Operations and Maintenance	2014	$	33	$	27
agreement		2013		31		25
Insurance premiums(c)	Other Operations and Maintenance	2014		(b)		(a)
		2013		(b)		(a)
Total Other Operations and		2014	$	33	$	27
Maintenance Expenses		2013		31		25
Money pool borrowings (advances)	Interest Charges	2014	$	(b)	$	(b)
		2013		(b)		(b)

(a) Not applicable.

(b) Amount less than $1 million.

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

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Commitments And Contingencies (Tables)

3 Months Ended

Mar. 31, 2014

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, 2014. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year. Both coverages were renewed in 2014.

Type and Source of Coverage	Maximum  Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	375		$	—
Pool participation	13,241		(a)	128		(b)
	$	13,616	(c)	$	128
Property damage:
NEIL	$	2,250	(d)	$	23	(e)
European Mutual Association for Nuclear Insurance	500		(f)	—
	$	2,750		$	23
Replacement power:
NEIL	$	490	(g)	$	9	(e)
Missouri Energy Risk Assurance Company LLC	64		(h)	—

(a) Provided through mandatory participation in an industrywide retrospective premium assessment program.

(b) Retrospective premium under the Price-Anderson Act. 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 $19 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 $128 million per incident for each licensed reactor it operates with a maximum of $19 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) NEIL provides $2.25 billion in property damage, decontamination, and premature decommissioning insurance. There is a $1.7 billion sublimit for nonradiation events, of which the last $200 million is a shared limit with other generators purchasing this coverage. The $1.7 billion sublimit for nonradiation events was not included with the April 1, 2014 renewal.

(e) All NEIL insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL.

(f) European Mutual Association for Nuclear Insurance provides $500 million in excess of the $2.25 billion property coverage provided by NEIL.

(g) Provides 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. Nonradiation events are sub-limited to $327.6 million.

(h) Provides 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 NEIL and is a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 8 - Related Party Transactions for more information on this affiliate transaction.

Schedule of Estimated Obligations for Manufactured Gas Plant Remediation

The following table presents, as of March 31, 2014, the estimated obligation to complete the remediation of these former MGP sites:

	Estimate				Recorded   Liability(a)
	Low		High
Ameren	$	269	$	345	$	269
Ameren Missouri	3		4		3
Ameren Illinois	266		341		266

(a) Recorded liability represents the estimated minimum probable obligations, as no other amount within the range was 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, 2014:

Ameren	Ameren Missouri	Ameren Illinois	Total(a)
1	47	56	71

(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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Summary Of Significant Accounting Policies

3 Months Ended

Mar. 31, 2014

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. 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, doing business as 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 Missouri supplies electric service to 1.2 million customers and natural gas service to 127,000 customers.

• Ameren Illinois Company, doing business as Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 807,000 customers.

Ameren has various other subsidiaries responsible for activities such as the provision of shared services. Ameren also has a subsidiary, ATXI, that operates a FERC rate-regulated electric transmission business and is developing the Illinois Rivers project.

The operating results, assets, and liabilities for New AER and the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers have been presented separately as discontinued operations for all periods presented in this report. Unless otherwise stated, these notes to Ameren’s financial statements exclude discontinued operations for all periods presented. On January 31, 2014, Medina Valley completed its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. See Note 12 - Divestiture Transactions and Discontinued Operations in this report for additional information regarding the discontinued operations presentation and Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information regarding Ameren’s divestiture of New AER in December 2013.

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. Ameren Missouri and Ameren Illinois have no subsidiaries, and therefore their financial statements are not prepared on a consolidated basis. 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, 2014, and 2013, caused by the assumed settlement of performance share units. The number of dilutive performance share units had an immaterial impact on earnings per share.

Stock-based Compensation

Ameren’s long-term incentive plan available for eligible employees, the 2006 Omnibus Incentive Compensation Plan (2006 Plan), was replaced prospectively for new grants only by the 2014 Omnibus Incentive Compensation Plan (2014 Plan) effective April 24, 2014. The 2014 Plan provides for a maximum of 8 million common shares to be available for grant to eligible employees and directors, and retains many of the features of the 2006 Plan. The 2014 Plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards.

A summary of nonvested performance share units at March 31, 2014, and changes during the three months ended March 31, 2014, under the 2006 Plan are presented below:

	Performance Share Units
	Share Units		Weighted-average Fair Value Per Unit at Grant Date
Nonvested at January 1, 2014	1,218,544		$	33.23
Granted(a)	680,606		38.90
Forfeitures	(46,758	)	33.29
Vested(b)	(116,297	)	38.81
Nonvested at March 31, 2014	1,736,095		$	35.08

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2014 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 2014 under the 2006 Plan was determined to be $38.90. That amount was based on Ameren’s closing common share price of $36.16 at December 31, 2013, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total stockholder return for a three-year performance period relative to the designated peer group beginning January 1, 2014. 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 0.78%, volatility of 12% to 18% 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 renewable energy credits and emission allowances 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, 2014, 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 $17 million each at March 31, 2014. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $22 million each at December 31, 2013.

Ameren Missouri’s and Ameren Illinois’ renewable energy credits and Ameren Missouri’s emission allowances are charged to “Purchased power” expense and “Fuel” expense, respectively, as they are used in operations. The following table presents amortization expense based on usage of renewable energy credits and emission allowances, net of gains from sales, for Ameren, Ameren Missouri and Ameren Illinois, during the three months ended March 31, 2014, and 2013:

	Three Months
	2014			2013
Ameren Missouri	$	6	(a)	$	(b)
Ameren Illinois		3			4
Ameren	$	9		$	4

(a) Includes higher priced renewable energy credits. 

(b) 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 customer and are therefore not included in revenues and expenses. They are 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, 2014, and 2013:

	Three months
	2014		2013
Ameren Missouri	$	34	$	33
Ameren Illinois	26		22
Ameren	$	60	$	55

Uncertain Tax Positions

The following table presents the amount of unrecognized tax benefits (detriments) as of March 31, 2014, and December 31, 2013:

	March 31, 2014			December 31, 2013
Ameren	$	92		$	90
Ameren Missouri	32			31
Ameren Illinois	(1		)	(1		)

With the adoption of new accounting guidance in the first quarter of 2014, unrecognized tax benefits are recorded in “Accumulated deferred income taxes, net” as a reduction to the deferred tax assets for net operating loss and tax credit carryforwards on Ameren’s, Ameren Missouri’s and Ameren Illinois’ balance sheets. Unrecognized tax benefits that exceed these carryforwards are recorded in “Other deferred credits and liabilities” on the respective balance sheets. At March 31, 2014, unrecognized tax benefits of $84 million, $14 million, and $- million were recorded in “Accumulated deferred income taxes, net” on Ameren's, Ameren Missouri's and Ameren Illinois' balance sheets, respectively. At December 31, 2013, unrecognized tax benefits of $84 million, $15 million, and $- million previously recorded in “Other deferred credits and liabilities” on the respective balance sheets were reclassified to “Accumulated deferred income taxes, net” for comparative purposes. For additional information see the Accounting and Reporting Developments section below.

The following table presents the amount of unrecognized tax benefits (detriments) as of March 31, 2014, and 2013, that would impact the effective tax rate, if recognized:

	March 31, 2014			December 31, 2013
Ameren	$	55		$	54
Ameren Missouri	2			3
Ameren Illinois	(1		)	—

Ameren’s federal income tax returns for the years 2007 through 2011 are before the Appeals Office of the IRS. Ameren’s federal income tax return for the year 2012 is currently under examination.

It is reasonably possible that a settlement will be reached with the Appeals Office of the IRS in the next 12 months for the years 2007 through 2011. This settlement, which is primarily related to uncertain tax positions for research tax deductions, is expected to result in a decrease in uncertain tax benefits of $20 million and $13 million for Ameren and Ameren Missouri, 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 at March 31, 2014, compared to December 31, 2013, to reflect the accretion of obligations to their fair value, partially offset by immaterial settlements.

Noncontrolling Interests

As of March 31, 2014, Ameren's noncontrolling interests were composed of the preferred stock not subject to mandatory redemption of Ameren Missouri and Ameren Illinois. All noncontrolling interests are classified as a component of equity separate from Ameren's equity on its consolidated balance sheet. A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren for the three months ended March 31, 2014, and 2013, are shown below:

	Three Months
	2014			2013
Noncontrolling interests, beginning of period	$	142		$	151		(a)
Net income from continuing operations attributable to noncontrolling interests	2			2
Dividends paid to noncontrolling interest holders	(2		)	(2		)
Noncontrolling interests, end of period	$	142		$	151		(a)

(a) Included the 20% EEI ownership interest not owned by Ameren prior to the divestiture of New AER to IPH. Prior to the divestiture of New AER, the assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Assets of discontinued operations” and “Liabilities of discontinued operations.” The divestiture of New AER, which included EEI, was completed in the fourth quarter of 2013. See Note 12 - Divestiture Transactions and Discontinued Operations for additional information.

Accounting and Reporting Developments

The following is a summary of recently adopted authoritative accounting guidance.

Presentation of an Unrecognized Tax Benefit

In July 2013, FASB issued additional authoritative accounting guidance to provide clarity for the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The objective of this guidance is to eliminate diversity in practice related to the presentation of certain unrecognized tax benefits. It requires entities to present an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward to the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is available under the tax law. This guidance was effective for the Ameren Companies beginning in the first quarter of 2014. Previously, unrecognized tax benefits were recorded in “Other deferred credits and liabilities” on Ameren's, Ameren Missouri's and Ameren Illinois' balance sheets. Beginning in the first quarter 2014, unrecognized tax benefits are recorded in “Accumulated deferred income taxes, net” as a reduction to the deferred tax assets for net operating loss and tax credit carryforwards on the respective balance sheets. Unrecognized tax benefits that exceed these carryforwards are recorded in “Other deferred credits and liabilities,” on the respective balance sheets. For comparative purposes, the Ameren Companies reclassified the December 31, 2013 balances in accordance with the new guidance as discussed in the Uncertain Tax Positions section above. The implementation of the additional authoritative accounting guidance did not affect the Ameren Companies' results of operations or liquidity, as this guidance is presentation-related only.

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Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2014

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, 2014, and 2013:

	Pension Benefits						Postretirement Benefits
	Three Months						Three Months
	2014			2013			2014			2013
Service cost	$	21		$	24		$	5		$	6
Interest cost	49			40			13			12
Expected return on plan assets	(57		)	(54		)	(16		)	(16		)
Amortization of:
Prior service cost (benefit)	—			(1		)	(1		)	(1		)
Actuarial loss	12			22			(1		)	2
Net periodic benefit cost	$	25		$	31		$	—		$	3

Summary Of Benefit Plan Costs Incurred

Ameren Missouri and Ameren Illinois are responsible for their respective shares of Ameren’s pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three months ended March 31, 2014, and 2013:

	Pension Costs				Postretirement Costs
	Three Months					Three Months
	2014		2013			2014			2013
Ameren Missouri	$	17	$	18		$	1		$	2
Ameren Illinois	8		10			(1		)	1
Other	—		3			—			—
Ameren(a)	$	25	$	31		$	—		$	3

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

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Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Schedule of Unrecognized Tax Benefits (Detriments) That Would Impact the Effective Tax Rate) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Schedule of Unrecognized Tax Benefits (Detriments) That Would Impact Effective Tax Rate [Line Items]
Unrecognized tax benefits (detriments) that would impact effective tax rate	$ 55	$ 54
Union Electric Company
Schedule of Unrecognized Tax Benefits (Detriments) That Would Impact Effective Tax Rate [Line Items]
Unrecognized tax benefits (detriments) that would impact effective tax rate	2	3
Ameren Illinois Company
Schedule of Unrecognized Tax Benefits (Detriments) That Would Impact Effective Tax Rate [Line Items]
Unrecognized tax benefits (detriments) that would impact effective tax rate	$ (1)	$ 0

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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, 2014		Dec. 31, 2013
Derivative [Line Items]
Current gains deferred as regulatory liabilities	$ 248		$ 216
Current losses deferred as regulatory assets	220		156
Fuel Oils
Derivative [Line Items]
Current gains deferred as regulatory liabilities	2
Current losses deferred as regulatory assets	1
Fuel Oils | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)		[1]	2
Natural Gas
Derivative [Line Items]
Current gains deferred as regulatory liabilities	6
Current losses deferred as regulatory assets	20
Natural Gas | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(30)	[2]	(55)
Power
Derivative [Line Items]
Current gains deferred as regulatory liabilities	15
Current losses deferred as regulatory assets	14
Power | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(111)	[3]	(89)
Uranium
Derivative [Line Items]
Current losses deferred as regulatory assets	4
Uranium | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(5)	[4]	(6)
Union Electric Company
Derivative [Line Items]
Current gains deferred as regulatory liabilities	47		57
Current losses deferred as regulatory assets	145		118
Union Electric Company | Fuel Oils
Derivative [Line Items]
Current gains deferred as regulatory liabilities	2
Current losses deferred as regulatory assets	1
Union Electric Company | Fuel Oils | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)		[1]	2
Union Electric Company | Natural Gas
Derivative [Line Items]
Current gains deferred as regulatory liabilities	1
Current losses deferred as regulatory assets	4
Union Electric Company | Natural Gas | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(6)	[2]	(10)
Union Electric Company | Power
Derivative [Line Items]
Current gains deferred as regulatory liabilities	15
Current losses deferred as regulatory assets	6
Union Electric Company | Power | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	9	[3]	19
Union Electric Company | Uranium
Derivative [Line Items]
Current losses deferred as regulatory assets	4
Union Electric Company | Uranium | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(5)	[4]	(6)
Ameren Illinois Company
Derivative [Line Items]
Current gains deferred as regulatory liabilities	201		159
Current losses deferred as regulatory assets	75		38
Ameren Illinois Company | Natural Gas
Derivative [Line Items]
Current gains deferred as regulatory liabilities	5
Current losses deferred as regulatory assets	16
Ameren Illinois Company | Natural Gas | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(24)	[2]	(45)
Ameren Illinois Company | Power
Derivative [Line Items]
Current losses deferred as regulatory assets	8
Ameren Illinois Company | Power | Regulatory Liabilities Or Assets [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	$ (120)	[3]	$ (108)

[1] Represents net gains (losses) on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through December 2016 as of March 31, 2014. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014

[2] Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2019 at Ameren and Ameren Missouri and through October 2017 at Ameren Illinois, in each case as of March 31, 2014. 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, 2014. Current losses deferred as regulatory assets include $20 million, $4 million, and $16 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2014.

[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, 2014. Current gains deferred as regulatory liabilities include $15 million and $15 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014. Current losses deferred as regulatory assets include $14 million, $6 million, and $8 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2014.

[4] Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through December 2016, as of March 31, 2014. Current losses deferred as regulatory assets include $4 million and $4 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014.

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Retirement Benefits (Components Of Net Periodic Benefit Cost) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Pension Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 21	$ 24
Interest cost	49	40
Expected return on plan assets	(57)	(54)
Prior service cost (benefit)	0	(1)
Actuarial loss	12	22
Net periodic benefit cost	25	31
Postretirement Benefit Costs [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	5	6
Interest cost	13	12
Expected return on plan assets	(16)	(16)
Prior service cost (benefit)	(1)	(1)
Actuarial loss	(1)	2
Net periodic benefit cost	$ 0	$ 3

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Consolidated Statement of Income (Loss) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Operating Revenues:
Electric	$ 1,106		$ 1,088
Gas	488		387
Total operating revenues	1,594		1,475
Operating Expenses:
Fuel	204		213
Purchased power	112		151
Gas purchased for resale	304		230
Other operations and maintenance	420		399
Depreciation and amortization	181		175
Taxes other than income taxes	127		122
Total operating expenses	1,348		1,290
Operating Income	246		185
Other Income and Expenses:
Miscellaneous income	18	[1]	15	[1]
Miscellaneous expense	9	[1]	8	[1]
Total other income (expense)	9		7
Interest Charges	92		101
Income Before Income Taxes	163		91
Income Taxes	64		35
Income from Continuing Operations	99		56
Loss from Discontinued Operations, Net of Taxes (Note 12)	(1)		(199)
Net Income (Loss)	98		(143)
Comprehensive Income (Loss)	96		(152)
Less: Net Income (Loss) Attributable to Noncontrolling Interests:
Net Income from Continuing Operations Attributable to Noncontrolling Interests	2		2
Net Income (Loss):
Continuing Operations	97		54
Discontinued Operations	(1)		(199)
Net Income (Loss)	96		(145)
Income (Loss) from Continuing Operations, Per Basic Share	$ 0.40		$ 0.22
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share	$ 0.00		$ (0.82)
Earnings Per Share, Basic	$ 0.40		$ (0.60)
Dividends per Common Share	$ 0.40		$ 0.40
Average Common Shares Outstanding - Basic	242.6		242.6
Union Electric Company
Operating Revenues:
Electric	749		732
Gas	68		64
Total operating revenues	817		796
Operating Expenses:
Fuel	204		213
Purchased power	33		26
Gas purchased for resale	40		37
Other operations and maintenance	227		221
Depreciation and amortization	116		111
Taxes other than income taxes	78		77
Total operating expenses	698		685
Operating Income	119		111
Other Income and Expenses:
Miscellaneous income	14		14
Miscellaneous expense	4		5
Total other income (expense)	10		9
Interest Charges	52		60
Income Before Income Taxes	77		60
Income Taxes	29		19
Net Income (Loss)	48		41
Other Comprehensive Income	0		0
Comprehensive Income (Loss)	48		41
Net Income (Loss):
Net Income (Loss)	48		41
Preferred Stock Dividends	1		1
Net Income Available to Common Stockholder	47		40
Ameren Illinois Company
Operating Revenues:
Electric	353		360
Gas	421		324
Total operating revenues	774		684
Operating Expenses:
Purchased power	81		127
Gas purchased for resale	264		193
Other operations and maintenance	200		176
Depreciation and amortization	63		61
Taxes other than income taxes	46		42
Total operating expenses	654		599
Operating Income	120		85
Other Income and Expenses:
Miscellaneous income	3		1
Miscellaneous expense	4		3
Total other income (expense)	(1)		(2)
Interest Charges	30		31
Income Before Income Taxes	89		52
Income Taxes	35		20
Net Income (Loss)	54		32
Pension and other postretirement benefit plan activity, net of income taxes (benefit)	(1)		(1)
Comprehensive Income (Loss)	53		31
Net Income (Loss):
Net Income (Loss)	54		32
Preferred Stock Dividends	1		1
Net Income Available to Common Stockholder	$ 53		$ 31

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

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Short-Term Debt And Liquidity (Narrative) (Detail) (USD $)							3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Ameren (parent) [Domain]	Dec. 31, 2013 Ameren (parent) [Domain]	Mar. 31, 2014 Union Electric Company	Dec. 31, 2013 Union Electric Company	Mar. 31, 2014 Utilities [Member]	Mar. 31, 2013 Utilities [Member]	Mar. 31, 2014 Credit Agreements 2012 [Member]	Mar. 31, 2014 Credit Agreements 2012 [Member] Maximum	Mar. 31, 2014 Missouri Credit Agreement 2012 [Member] Union Electric Company	Mar. 31, 2014 Illinois Credit Agreement 2012 [Member] Ameren Illinois Company
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity									$ 1,400,000,000
Commercial paper outstanding	$ 700,000,000	$ 368,000,000	$ 410,000,000	$ 368,000,000	$ 290,000,000
Actual debt-to-capital ratio									0.50	0.65	0.49	0.44
Minimum ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date									2.0 to 1.0
Current ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date									5.6 to 1.0
Short Term Debt, Weighted Average Interest Rate During Period							0.39%	0.11%

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Consolidated Balance Sheet (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Accounts receivable - trade allowance for doubtful accounts	$ 26	$ 18
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
Accounts receivable - trade allowance for doubtful accounts	7	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
Accounts receivable - trade allowance for doubtful accounts	$ 18	$ 13
Common stock, no par value
Common stock, shares authorized	45.0	45.0
Common stock, shares outstanding	25.5	25.5

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Fair Value Measurements (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Valuation adjustments related to net derivative contracts, liabilities	$ 1	$ 3
Union Electric Company
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
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Valuation adjustments related to net derivative contracts, liabilities	$ 1	$ 3

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Summary Of Significant Accounting Policies (Narrative) (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Dec. 31, 2013
Basis Of Presentation And Significant Accounting Policies [Line Items]
Maximum shares available for grants	8
Closing common share price			$ 36.16
Book value of renewable energy credits	$ 17		$ 22
Unrecognized tax benefit recorded in Accumulated deferred income taxes, net	84		84
Estimated unrecognized tax decreases resulting from settlements with taxing authorities	20
Union Electric Company
Basis Of Presentation And Significant Accounting Policies [Line Items]
Book value of renewable energy credits	17		22
Unrecognized tax benefit recorded in Accumulated deferred income taxes, net	14		15
Estimated unrecognized tax decreases resulting from settlements with taxing authorities	13
Ameren Illinois Company
Basis Of Presentation And Significant Accounting Policies [Line Items]
Unrecognized tax benefit recorded in Accumulated deferred income taxes, net	$ 0		$ 0
Electric Energy, Inc
Basis Of Presentation And Significant Accounting Policies [Line Items]
Percentage of EEI not owned by Ameren			20.00%
Performance Shares
Basis Of Presentation And Significant Accounting Policies [Line Items]
Fair value of each share unit, per share	$ 38.90	[1]
Performance period	3 years
Risk free interest rate period	3 years
Three-year risk-free rate	0.78%
Volatility rate, minimum	12.00%
Volatility rate, maximum	18.00%
Power | Union Electric Company
Basis Of Presentation And Significant Accounting Policies [Line Items]
Number of customers			1,200,000
Power | Ameren Illinois Company
Basis Of Presentation And Significant Accounting Policies [Line Items]
Number of customers			1,200,000
Natural Gas | Union Electric Company
Basis Of Presentation And Significant Accounting Policies [Line Items]
Number of customers			127,000
Natural Gas | Ameren Illinois Company
Basis Of Presentation And Significant Accounting Policies [Line Items]
Number of customers			807,000

[1] Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2014 under the 2006 Plan.

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Commitments And Contingencies (Callaway Energy Center) (Detail) (USD $)	3 Months Ended
	Mar. 31, 2014
Commitments And Contingencies [Line Items]
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	19,000,000
Aggregate maximum assessment per incident under Price-Anderson liability provisions of Atomic Energy Act	128,000,000
Maximum annual payment in calendar year per reactor incident under Price Andersen Liability Provisions of Atomic Energy Act	19,000,000
Amount of coverage in excess of primary property liability coverage	2,250,000,000.00
Sub-limit of Amount of Coverage in Excess of Primary Property Liability Coverage for Non-Nuclear Events	1,700,000,000
Amount of weekly indemnity coverage commencing eight weeks after power outage	4,500,000.0
Number of weeks of coverage after the first eight weeks of an outage	1 year
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	1 year 4 months 10 days
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
Public Liability
Commitments And Contingencies [Line Items]
Maximum Coverages	13,616,000,000	[1]
Maximum Assessments for Single Incidents	128,000,000
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	13,241,000,000	[2]
Maximum Assessments for Single Incidents	128,000,000	[3]
Property Damage
Commitments And Contingencies [Line Items]
Maximum Coverages	2,750,000,000
Maximum Assessments for Single Incidents	23,000,000
Property Damage - Nuclear Electric Insurance Ltd [Member]
Commitments And Contingencies [Line Items]
Maximum Coverages	2,250,000,000	[4]
Maximum Assessments for Single Incidents	23,000,000	[5]
Sub-limit of Amount of Coverage in Excess of Primary Property Liability Coverage for Non-Nuclear Events	200,000,000
Property Damage European Mutual Association for Nuclear Insurance [Member]
Commitments And Contingencies [Line Items]
Maximum Coverages	500,000,000	[6]
Amount of primary property liability coverage	500,000,000
Replacement Power - Nuclear Electric Insurance Ltd [Member]
Commitments And Contingencies [Line Items]
Maximum Coverages	490,000,000	[7]
Maximum Assessments for Single Incidents	9,000,000	[5]
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	[8]
Amount of weekly indemnity coverage thereafter not exceeding policy limit	$ 3,600,000

[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 $128 million per incident for each licensed reactor it operates with a maximum of $19 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] Provided through mandatory participation in an industrywide retrospective premium assessment program.

[3] Retrospective premium under the Price-Anderson Act. 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 $19 million per year.

[4] provides $2.25 billion in property damage, decontamination, and premature decommissioning insurance.

[5] All NEIL insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL.

[6] European Mutual Association for Nuclear Insurance provides $500 million in excess of the $2.25 billion property coverage provided by NEIL.

[7] Provides 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. Nonradiation events are sub-limited to $327.6 million.

[8] Provides 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 NEIL and is a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 8 - Related Party Transactions for more information on this affiliate transaction.

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Derivative Financial Instruments Derivative Financial Instruments (Policies)

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

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

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

• market values of 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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Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Summary of Nonvested Shares Related To Long-Term Incentive Plan) (Details) (Performance Shares, USD $)	3 Months Ended
	Mar. 31, 2014
Performance Shares
Share Units
Share Units, Nonvested as of January 1, 2014	1,218,544
Share Units, Granted	680,606	[1]
Share Units, Forfeitures	(46,758)
Share Units, Vested	(116,297)	[2]
Share Units, Nonvested as of March 31, 2014	1,736,095
Weighted-average Fair Value per Unit at Grant Date
Weighted-average Fair Value per Unit, Nonvested as of January 1, 2014	$ 33.23
Weighted-average Fair Value per Unit, Grants	$ 38.90	[1]
Weighted-average Fair Value per Unit, Forfeitures	$ 33.29
Weighted-average Fair Value per Unit, Vested	$ 38.81	[2]
Weighted-average Fair Value per Unit, Nonvested as of March 31, 2014	$ 35.08
Performance period	3 years

[1] Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2014 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.

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Summary Of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Summary Of Nonvested Shares Related To Long-Term Incentive Plan

A summary of nonvested performance share units at March 31, 2014, and changes during the three months ended March 31, 2014, under the 2006 Plan are presented below:

	Performance Share Units
	Share Units		Weighted-average Fair Value Per Unit at Grant Date
Nonvested at January 1, 2014	1,218,544		$	33.23
Granted(a)	680,606		38.90
Forfeitures	(46,758	)	33.29
Vested(b)	(116,297	)	38.81
Nonvested at March 31, 2014	1,736,095		$	35.08

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2014 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, 2014, and 2013:

	Three Months
	2014			2013
Ameren Missouri	$	6	(a)	$	(b)
Ameren Illinois		3			4
Ameren	$	9		$	4

(a) Includes higher priced renewable energy credits. 

(b) 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, 2014, and 2013:

	Three months
	2014		2013
Ameren Missouri	$	34	$	33
Ameren Illinois	26		22
Ameren	$	60	$	55

Schedule of Unrecognized Tax Benefits

The following table presents the amount of unrecognized tax benefits (detriments) as of March 31, 2014, and December 31, 2013:

	March 31, 2014			December 31, 2013
Ameren	$	92		$	90
Ameren Missouri	32			31
Ameren Illinois	(1		)	(1		)

Schedule of Unrecognized Tax Benefits That Would Impact Effective Tax Rate

The following table presents the amount of unrecognized tax benefits (detriments) as of March 31, 2014, and 2013, that would impact the effective tax rate, if recognized:

	March 31, 2014			December 31, 2013
Ameren	$	55		$	54
Ameren Missouri	2			3
Ameren Illinois	(1		)	—

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, 2014, and 2013, are shown below:

	Three Months
	2014			2013
Noncontrolling interests, beginning of period	$	142		$	151		(a)
Net income from continuing operations attributable to noncontrolling interests	2			2
Dividends paid to noncontrolling interest holders	(2		)	(2		)
Noncontrolling interests, end of period	$	142		$	151		(a)

(a) Included the 20% EEI ownership interest not owned by Ameren prior to the divestiture of New AER to IPH. Prior to the divestiture of New AER, the assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Assets of discontinued operations” and “Liabilities of discontinued operations.” The divestiture of New AER, which included EEI, was completed in the fourth quarter of 2013. See Note 12 - Divestiture Transactions and Discontinued Operations for additional information.

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Commitments And Contingencies (Pumped-Storage Hydroelectric Facility Breach) (Detail) (Union Electric Company, USD $) In Millions, unless otherwise specified	Mar. 31, 2014
Union Electric Company
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, 2014		Mar. 31, 2013
Cash Flows From Operating Activities:
Net income (loss)	$ 98		$ (143)
Loss from discontinued operations, net of taxes	1		199
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	176		166
Amortization of nuclear fuel	24		20
Amortization of debt issuance costs and premium/discounts	5		6
Deferred income taxes and investment tax credits, net	84		40
Allowance for equity funds used during construction	(7)	[1]	(8)	[1]
Stock-based compensation costs	9		9
Other	(1)		(3)
Changes in assets and liabilities:
Receivables	(86)		(95)
Materials and supplies	102		127
Accounts and wages payable	(183)		(127)
Taxes accrued	18		41
Assets, other	(90)		52
Liabilities, other	49		29
Pension and other postretirement benefits	30		3
Counterparty collateral, net	10		26
Net cash provided by operating activities – continuing operations	239		342
Net cash provided by operating activities – discontinued operations			37
Net cash provided by operating activities	239		379
Cash Flows From Investing Activities:
Capital expenditures	(442)		(275)
Nuclear fuel expenditures	(10)		(11)
Purchases of securities - nuclear decommissioning trust fund	(186)		(35)
Sales and maturities of securities - nuclear decommissioning trust fund	182		32
Proceeds from Notes Receivable	56
Contributions to Note Receivable	(65)
Other			(2)
Net cash used in investing activities – continuing operations	(465)		(291)
Net cash provided by (used in) investing activities – discontinued operations	152		(12)
Net cash used in investing activities	(313)		(303)
Cash Flows From Financing Activities:
Dividends on common stock	(97)		(97)
Dividends paid to noncontrolling interest holders	(2)		(2)
Short-term debt, net	332
Redemptions of Other Long-term Debt	(163)
Net cash provided by (used in) financing activities – continuing operations	70		(99)
Net cash used in financing activities – discontinued operations
Net cash provided by (used in) financing activities	70		(99)
Net change in cash and cash equivalents	(4)		(23)
Cash and cash equivalents at beginning of period	30		209
Cash and cash equivalents at end of period	26		186
Less cash and cash equivalents at end of period, discontinued operations			25
Cash and cash equivalents at beginning of period	30
Cash and cash equivalents at end of period	26		161
Union Electric Company
Cash Flows From Operating Activities:
Net income (loss)	48		41
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	112		104
Amortization of nuclear fuel	24		20
Amortization of debt issuance costs and premium/discounts	2		2
Deferred income taxes and investment tax credits, net	30		(8)
Allowance for equity funds used during construction	(7)		(7)
Changes in assets and liabilities:
Receivables	2		(50)
Materials and supplies	14		22
Accounts and wages payable	(153)		(139)
Taxes accrued	30		38
Assets, other	(28)		38
Liabilities, other	7		5
Pension and other postretirement benefits	15		2
Net cash provided by operating activities	96		68
Cash Flows From Investing Activities:
Capital expenditures	(188)		(137)
Nuclear fuel expenditures	(10)		(11)
Money pool advances, net			24
Purchases of securities - nuclear decommissioning trust fund	(186)		(35)
Sales and maturities of securities - nuclear decommissioning trust fund	182		32
Other	(2)		(2)
Net cash used in investing activities	(204)		(129)
Cash Flows From Financing Activities:
Dividends on common stock	(77)		(90)
Dividends on preferred stock	(1)		(1)
Money pool borrowings, net	(105)		5
Short-term debt, net	290
Net cash provided by (used in) financing activities	107		(86)
Net change in cash and cash equivalents	(1)		(147)
Cash and cash equivalents at beginning of period	1		148
Cash and cash equivalents at end of period			1
Ameren Illinois Company
Cash Flows From Operating Activities:
Net income (loss)	54		32
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	62		60
Amortization of debt issuance costs and premium/discounts	3		3
Deferred income taxes and investment tax credits, net	36		50
Other	(2)		(1)
Changes in assets and liabilities:
Receivables	(94)		(58)
Materials and supplies	88		105
Accounts and wages payable	14		9
Taxes accrued	(1)		3
Assets, other	(61)		16
Liabilities, other	71		24
Pension and other postretirement benefits	10		1
Counterparty collateral, net	12		27
Net cash provided by operating activities	192		271
Cash Flows From Investing Activities:
Capital expenditures	(215)		(133)
Money pool advances, net			(5)
Other	1
Net cash used in investing activities	(214)		(138)
Cash Flows From Financing Activities:
Dividends on common stock			(15)
Dividends on preferred stock	(1)		(1)
Money pool borrowings, net	186		(24)
Redemptions of Other Long-term Debt	(163)
Net cash provided by (used in) financing activities	22		(40)
Net change in cash and cash equivalents			93
Cash and cash equivalents at beginning of period	1
Cash and cash equivalents at end of period	$ 1		$ 93

[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, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Ameren Illinois Company
Pension and other postretirement benefit plan activity, tax expense (benefit)	$ (1)	$ (1)

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Callaway Energy Center

3 Months Ended

Mar. 31, 2014

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 utilities that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established the fee that these utilities pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each 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 Missouri and other utilities have entered into standard contracts with the federal government. The government, represented by the DOE, is responsible for implementing these provisions of the NWPA. Consistent with the NWPA and its 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.

Although both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, the federal government is not meeting its disposal obligation. Ameren Missouri has sufficient installed capacity at the Callaway energy center to store its spent nuclear fuel generated through 2020, and it has the capability for additional storage capacity for spent nuclear fuel generated through the end of the energy center’s current license. 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 operations of the energy center.

In January 2009, the federal government announced that a spent nuclear fuel repository at Yucca Mountain, Nevada was unworkable. The federal government took steps to terminate the Yucca Mountain program, while acknowledging its continuing obligation to dispose of utilities’ spent nuclear fuel. In January 2013, the DOE issued its plan for the management and disposal of spent nuclear fuel. 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, co-located with the pilot facility. The plan also proposes to site a permanent geological repository by 2026, to characterize the site and to design and to license the repository by 2042, and to begin operation by 2048.

In view of the federal government's efforts to terminate the Yucca Mountain program, the Nuclear Energy Institute, a number of individual utilities, and the National Association of Regulatory Utility Commissioners sued the DOE in the United States Court of Appeals for the District of Columbia Circuit, seeking the suspension of the one mill nuclear waste fee, alleging that the DOE failed to undertake an appropriate fee adequacy review reflecting the current unsettled state of the nuclear waste program. In a June 2012 decision, the court ruled that the DOE's fee adequacy review was legally inadequate and remanded the matter to the DOE. Although the court ruled it has the power to direct the DOE to suspend the fee, the court decided that it was premature to do so. Instead, the court ordered the DOE to provide within six months a revised assessment of the amount that should be collected. In January 2013, the DOE issued the revised assessment required by the court. The DOE determined that “neither insufficient nor excess revenues are being collected,” and it proposed no adjustment to the one mill nuclear waste fee. In November 2013, the court rejected the DOE's revised assessment and ordered the DOE to submit a proposal to the United States Congress to reduce the fee to zero. In January 2014, the DOE submitted a proposal to the United States Congress to reduce the fee to zero. Absent further action by the DOE, the fee reduction is expected to take effect during the second quarter of 2014. The nuclear waste fee is included in Ameren Missouri’s FAC. Therefore, if the fee is reduced to zero, the cost reduction will be passed on to electric utility customers with no material effect on Ameren’s and Ameren Missouri’s net income.

As a result of the DOE's failure to begin to dispose of spent nuclear fuel from commercial nuclear energy centers and fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners have also 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. It sought reimbursement for 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 the DOE performed its contractual obligations. In June 2011, the parties entered into a settlement agreement that provides for annual recovery of additional spent fuel storage and related costs incurred from 2010 through 2013 with the ability to extend the recovery period as mutually agreed to by the parties. The parties have agreed in principle to extend the recovery period through 2016. In March 2014, Ameren Missouri submitted its 2013 costs to the DOE for reimbursement under the settlement agreement. Ameren Missouri expects to receive the 2013 cost reimbursement of approximately $15 million during the third quarter of 2014. This reimbursement is included in "Miscellaneous accounts and notes receivable" on Ameren’s and Ameren Missouri’s March 31, 2014 and December 31, 2013 balance sheets. Included in these reimbursements are costs related to a dry spent fuel storage facility Ameren Missouri is constructing at its Callaway energy center. Ameren Missouri intends to begin transferring spent fuel assemblies to this facility in 2015. Until the facility is completed, Ameren Missouri will apply for reimbursement from the DOE for the cost to construct the dry spent fuel storage facility along with related allowable costs.

In December 2011, Ameren Missouri submitted a license extension application to 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 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.

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. Amounts collected from customers are deposited into the external nuclear decommissioning trust fund to provide for the Callaway energy center’s decommissioning. 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 2013, 2012, and 2011. 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. The last cost study and funding analysis were filed with the MoPSC in September 2011. In October 2012, the MoPSC issued an order approving the stipulation and agreement between Ameren Missouri and the MoPSC staff that maintained the current rate of deposits to the trust fund and the rate of return assumptions used in the analysis. 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 the next triennial cost study and funding analysis is approved by the MoPSC. 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 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 2 – Rate and Regulatory Matters for additional information related to the Callaway energy center.

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Document and Entity Information	3 Months Ended
	Mar. 31, 2014	Apr. 30, 2014
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Trading Symbol	AEE
Entity Registrant Name	AMEREN CORP
Entity Central Index Key	0001002910
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		242,634,798
Union Electric Company
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Entity Registrant Name	UNION ELECTRIC CO
Entity Central Index Key	0000100826
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		102,123,834
Ameren Illinois Company
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Entity Registrant Name	AMEREN ILLINOIS CO
Entity Central Index Key	0000018654
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		25,452,373

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Retirement Benefits

3 Months Ended

Mar. 31, 2014

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, 2014, the plan’s estimated investment performance through March 31, 2014, and Ameren’s pension funding policy, Ameren expects to make annual contributions of $20 million to $100 million in each of the next five years, with aggregate estimated contributions of $270 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 employees’ beneficiary association 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, 2014, and 2013:

	Pension Benefits						Postretirement Benefits
	Three Months						Three Months
	2014			2013			2014			2013
Service cost	$	21		$	24		$	5		$	6
Interest cost	49			40			13			12
Expected return on plan assets	(57		)	(54		)	(16		)	(16		)
Amortization of:
Prior service cost (benefit)	—			(1		)	(1		)	(1		)
Actuarial loss	12			22			(1		)	2
Net periodic benefit cost	$	25		$	31		$	—		$	3

Ameren Missouri and Ameren Illinois are responsible for their respective shares of Ameren’s pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three months ended March 31, 2014, and 2013:

	Pension Costs				Postretirement Costs
	Three Months					Three Months
	2014		2013			2014			2013
Ameren Missouri	$	17	$	18		$	1		$	2
Ameren Illinois	8		10			(1		)	1
Other	—		3			—			—
Ameren(a)	$	25	$	31		$	—		$	3

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

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Consolidated Statement of Comprehensive Income (Loss) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Income from Continuing Operations	$ 99	$ 56
Other Comprehensive Income, Net of Taxes
Other Comprehensive Income, Net of Taxes	0	0
Comprehensive Income from Continuing Operations	99	56
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests	2	2
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation	97	54
Loss from Discontinued Operations, Net of Taxes	(1)	(199)
Other Comprehensive Loss from Discontinued Operations, Net of Taxes	0	(7)
Comprehensive Loss from Discontinued Operations Attributable to Ameren Corporation	(1)	(206)
Comprehensive Income (Loss)	$ 96	$ (152)

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Other Income and Expenses

3 Months Ended

Mar. 31, 2014

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, 2014, and 2013:

	Three Months
	2014		2013
Ameren:(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	7	$	8
Interest income on industrial development revenue bonds	7		7
Interest and dividend income	2		—
Other	2		—
Total miscellaneous income	$	18	$	15
Miscellaneous expense:
Donations	$	5	$	4
Other	4		4
Total miscellaneous expense	$	9	$	8
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	7	$	7
Interest income on industrial development revenue bonds	7		7
Total miscellaneous income	$	14	$	14
Miscellaneous expense:
Donations	$	2	$	2
Other	2		3
Total miscellaneous expense	$	4	$	5
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	—	$	1
Interest and dividend income	2		—
Other	1		—
Total miscellaneous income	$	3	$	1
Miscellaneous expense:
Donations	$	3	$	3
Other	1		—
Total miscellaneous expense	$	4	$	3

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

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Long-Term Debt And Equity Financings

3 Months Ended

Mar. 31, 2014

Long-Term Debt And Equity Financings [Abstract]

LONG-TERM DEBT AND EQUITY FINANCINGS

LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren Missouri

In April 2014, Ameren Missouri issued $350 million of 3.50% senior secured notes due April 15, 2024, with interest payable semiannually on April 15 and October 15 of each year, beginning October 15, 2014. Ameren Missouri received $348 million. The proceeds were used to repay a portion of its short-term debt and will be used to repay at maturity $104 million of its 5.50% senior secured notes due May 15, 2014.

Ameren Illinois

In January 2014, Ameren Illinois redeemed the following environmental improvement and pollution control revenue bonds at par value plus accrued interest:

Environmental improvement and pollution control revenue bonds	Principal Amount
5.90% Series 1993 due 2023(a)	$	32
5.70% 1994A Series due 2024(a)	36
1993 Series C-1 5.95% due 2026	35
1993 Series C-2 5.70% due 2026	8
5.40% 1998A Series due 2028	19
5.40% 1998B Series due 2028	33
Total amount redeemed	$	163

(a) Less than $1 million principal amount of the bonds remain outstanding after redemption.

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, 2014, at an assumed annual 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	$	4,018		≥2.5	118.8	$	2,272
Ameren Illinois	≥2.0	7.6		3,732	(d)	≥1.5	2.7		203	(e)

(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 $729 million and $454 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.

(e) Preferred stock issuable is restricted by the amount of preferred stock that is currently authorized by Ameren Illinois’ articles of incorporation.

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.” 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. As of March 31, 2014, Ameren Illinois’ ratio of common stock equity to total capitalization was 55%.

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, 2014, 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. See Note - 12 Divestiture Transactions and Discontinued Operations for Ameren (parent) guarantees and letters of credit issued to support New AER based on the transaction agreement with IPH.

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Retirement Benefits Retirement Benefits (Policies)

3 Months Ended

Mar. 31, 2014

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

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, 2014, the plan’s estimated investment performance through March 31, 2014, and Ameren’s pension funding policy, Ameren expects to make annual contributions of $20 million to $100 million in each of the next five years, with aggregate estimated contributions of $270 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 employees’ beneficiary association trusts to match the annual postretirement expense.

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Divestiture Transactions and Discontinued Operations (Notes)

3 Months Ended

Mar. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS

DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS

On December 2, 2013, Ameren completed the divestiture of New AER to IPH, in accordance with the transaction agreement between Ameren and IPH dated March 14, 2013, as amended by a letter agreement dated December 2, 2013. The transaction agreement with IPH provides that if the Elgin, Gibson City, and Grand Tower gas-fired energy centers are subsequently sold to a third party and Medina Valley receives proceeds within two years of the closing of the New AER divestiture, 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, which totaled $137.5 million.

On January 31, 2014, Medina Valley completed the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital for a total purchase price of $168 million, before consideration of a net working capital adjustment. The agreement with Rockland Capital required $17 million of the purchase price to be held in escrow until the two-year anniversary of the closing of the sale to fund certain indemnity obligations, if any, of Medina Valley. The Rockland Capital escrow receivable balance is reflected on Ameren's March 31, 2014 consolidated balance sheet in "Other assets." The corresponding payable due to Genco is reflected on Ameren's March 31, 2014 consolidated balance sheet in "Other deferred credits and liabilities." An immaterial net working capital adjustment with Rockland Capital is expected to be finalized during the second quarter of 2014. Medina Valley expects to pay Genco any remaining portion of the escrow balance on January 31, 2016. Ameren did not record a gain from its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers.

Discontinued Operations Presentation

New AER and the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers have been classified collectively in Ameren’s consolidated financial statements as discontinued operations for all periods presented in this report. The disposal groups have been aggregated in the disclosures below. See Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information related to disposal groups. The following table presents the components of discontinued operations in Ameren's consolidated statement of income (loss) for the three months ended March 31, 2014, and 2013:

	Three months
	2014			2013
Operating revenues	$	1		$	264
Operating expenses	(2		)	(415		)	(a)
Operating loss	(1		)	(151		)
Other loss	—			(2		)
Interest charges	—			(11		)
Loss before income taxes	(1		)	(164		)
Income tax expense	—			(35		)
Loss from discontinued operations, net of taxes	$	(1	)	$	(199	)

(a) Included a noncash pretax asset 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.

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. Also during the three months ended March 31, 2013, Ameren adjusted the accumulated deferred income taxes on its consolidated balance sheet to reflect the excess of tax basis over financial reporting basis of its stock investment in AER, when it became apparent 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 then-expected tax benefits of $63 million related to the pretax loss from discontinued operations including the impairment charge, during the three months ended March 31, 2013.

During the three months ended March 31, 2014, Ameren recorded adjustments for its estimate of the New AER net working capital adjustment and for certain contingent liabilities associated with the New AER divestiture to IPH. Ameren also recognized the operating revenues and operating expenses associated with the Elgin, Gibson City, and Grand Tower energy centers prior to the completion of their sale to Rockland Capital on January 31, 2014. The operating expenses associated with the abandoned Meredosia and Hutsonville energy centers were also included in discontinued operations. The aggregate result of these items was a $1 million loss from discontinued operations during the three months ended March 31, 2014.

Ameren and IPH are in the process of finalizing the net working capital adjustment. Additionally, the final tax basis of the AER disposal group and the related tax benefit resulting from the transaction agreement, as amended, with IPH are dependent upon 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 ultimately realized in discontinued operations may differ materially from those recorded as of March 31, 2014.

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, 2014, and December 31, 2013:

	March 31, 2014		December 31, 2013
Assets of discontinued operations
Cash and cash equivalents	$	—	$	—
Accounts receivable and unbilled revenue	—		5
Materials and supplies	—		5
Property and plant, net	—		142
Accumulated deferred income taxes, net(a)	15		13
Total assets of discontinued operations	$	15	$	165
Liabilities of discontinued operations
Accounts payable and other current obligations	$	2	$	5
Asset retirement obligations(b)	31		40
Total liabilities of discontinued operations	$	33	$	45

(a) Balances primarily consist of deferred income tax assets related to the abandoned Meredosia and Hutsonville energy centers.

(b) Includes AROs associated with the abandoned Meredosia and Hutsonville energy centers of $31 million at March 31, 2014, and December 31, 2013.

Pursuant to the IPH transaction agreement, as amended, Ameren is obligated to pay up to $34 million for certain contingent liabilities. Of these liabilities, $29 million were included in "Other deferred credits and liabilities" and $5 million were included in "Accounts and wages payable" on Ameren's March 31, 2014 consolidated balance sheet.

The note receivable from Marketing Company related to the cash collateral support provided to New AER was $27 million and $18 million at March 31, 2014, and December 31, 2013, respectively, and was reflected on Ameren's consolidated balance sheet in "Other assets." This receivable to Ameren is due, with interest, on December 2, 2015, or sooner as cash collateral requirements are reduced. This cash collateral support is part of Ameren’s obligation to provide credit support to New AER until December 2, 2015, as discussed below.

Ameren Guarantees and Letters of Credit

The transaction agreement, as amended, requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the December 2, 2013, closing date of the divestiture. Ameren must also provide such additional credit support as required by contracts entered into prior to the closing date, in each case until December 2, 2015. IPH shall indemnify Ameren for any payments Ameren makes pursuant to these credit support obligations if the counterparty does not return the posted collateral to Ameren. IPH's indemnification obligation is 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 until December 2, 2015.

At March 31, 2014, Ameren had a total of $184 million in guarantees outstanding for New AER, which included:

• $171 million related to guarantees supporting Marketing Company for physically and financially settled power transactions with its counterparties that were in place at the December 2, 2013 closing of the divestiture, as well as for Marketing Company's clearing broker and other service agreements. If Marketing Company did not fulfill its obligations to these counterparties who had active open positions as of March 31, 2014, Ameren would have been required under its guarantees to provide $17 million to the counterparties.

• $13 million related to requirements for leasing agreements and potential environmental obligations.

Additionally, at March 31, 2014, Ameren had issued letters of credit totaling $9 million as credit support on behalf of New AER.

Ameren has not recorded a reserve for these contingent obligations because it does not believe a payment with respect to any of these guarantees was probable as of March 31, 2014.

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Related Party Transactions

3 Months Ended

Mar. 31, 2014

Related Party Transactions [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 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.

Collateral Postings

Under the terms of the Illinois power procurement agreements entered into through an RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Ameren Missouri, as a winning supplier in the RFP process, may be required to post collateral to Ameren Illinois. As of March 31, 2014, and December 31, 2013, there were no collateral postings required of Ameren Missouri related to the Illinois power procurement agreements.

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three months ended March 31, 2014, and 2013. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K, and the money pool arrangements discussed in Note 3 - Short-term Debt and Liquidity of this report.

				Three Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2014	$	(b)	$	(a)
agreements with Ameren Illinois		2013		1		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2014		5		(b)
rent and facility services		2013		5		(b)
Total Operating Revenues		2014	$	5	$	(b)
		2013		6		(b)
Ameren Illinois power supply	Purchased Power	2014	$	(a)	$	(b)
agreements with Ameren Missouri		2013		(a)		1
Ameren Illinois transmission	Purchased Power	2014		(a)		1
services with ATXI		2013		(a)		1
Total Purchased Power		2014	$	(a)	$	1
		2013		(a)		2
Ameren Services support services	Other Operations and Maintenance	2014	$	33	$	27
agreement		2013		31		25
Insurance premiums(c)	Other Operations and Maintenance	2014		(b)		(a)
		2013		(b)		(a)
Total Other Operations and		2014	$	33	$	27
Maintenance Expenses		2013		31		25
Money pool borrowings (advances)	Interest Charges	2014	$	(b)	$	(b)
		2013		(b)		(b)

(a) Not applicable.

(b) Amount less than $1 million.

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

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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, 2014		Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	$ 501	[1]	$ 494
Assets fair value	529	[2]	528	[2]
Excluded receivables, payables, and accrued income, net	2
Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	501	[1]	494
Assets fair value	524	[2]	527	[2]
Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	28	[2]	34	[2]
Derivative liabilities	172	[2]	178	[2]
Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	23	[2]	33	[2]
Derivative liabilities	23	[2]	24	[2]
Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	5		1
Derivative liabilities	149	[2]	154	[2]
Commodity Contract | Fuel Oils
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	6	[2]	9	[2]
Derivative liabilities	4	[2]	3	[2]
Commodity Contract | Fuel Oils | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	6	[2]	9	[2]
Derivative liabilities	4	[2]	3	[2]
Commodity Contract | Natural Gas
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	7	[2]	2	[2]
Derivative liabilities	37	[2]	57	[2]
Commodity Contract | Natural Gas | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	2	[2]	1	[2]
Derivative liabilities	8	[2]	11	[2]
Commodity Contract | Natural Gas | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	5	[2]	1	[2]
Derivative liabilities	29	[2]	46	[2]
Commodity Contract | Power
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	15	[2]	23	[2]
Derivative liabilities	126	[2]	112	[2]
Commodity Contract | Power | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	15	[2]	23	[2]
Derivative liabilities	6	[2]	4	[2]
Commodity Contract | Power | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	120	[2]	108	[2]
Commodity Contract | Uranium
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	5	[2]	6	[2]
Commodity Contract | Uranium | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	5	[2]	6	[2]
Cash and cash equivalents
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	2		3
Cash and cash equivalents | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	2		3
Equity Securities | U.S. large capitalization
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	327		332
Equity Securities | U.S. large capitalization | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	327		332
Debt Securities | Corporate bonds
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	61		52
Debt Securities | Corporate bonds | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	61		52
Debt Securities | Municipal bonds
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	2		2
Debt Securities | Municipal bonds | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	2		2
Debt Securities | US treasury and government securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	94		94
Debt Securities | US treasury and government securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	94		94
Debt Securities | Asset-backed Securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	14		10
Debt Securities | Asset-backed Securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	14		10
Debt Securities | Other Debt Securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1		1
Debt Securities | Other Debt Securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1		1
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	329		335
Assets fair value	330	[2]	336	[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	329		335
Assets fair value	330	[2]	336	[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[2]	1	[2]
Derivative liabilities	2	[2]	3	[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[2]	1	[2]
Derivative liabilities	2	[2]	3	[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Fuel Oils
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[2]	1	[2]
Derivative liabilities		[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Fuel Oils | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[2]	1	[2]
Derivative liabilities		[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Natural Gas
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		[2]		[2]
Derivative liabilities	2	[2]	3	[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Natural Gas | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		[2]		[2]
Derivative liabilities	2	[2]	3	[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Natural Gas | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		[2]
Derivative liabilities				[2]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Cash and cash equivalents
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	2		3
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Cash and cash equivalents | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	2		3
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Equity Securities | U.S. large capitalization
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	327		332
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Equity Securities | U.S. large capitalization | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	327		332
Significant Other Observable Inputs (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	172		159
Assets fair value	179	[2]	163	[2]
Significant Other Observable Inputs (Level 2) | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	172		159
Assets fair value	174	[2]	162	[2]
Significant Other Observable Inputs (Level 2) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	7	[2]	4	[2]
Derivative liabilities	36	[2]	56	[2]
Significant Other Observable Inputs (Level 2) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	2	[2]	3	[2]
Derivative liabilities	7	[2]	10	[2]
Significant Other Observable Inputs (Level 2) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	29	[2]	46	[2]
Significant Other Observable Inputs (Level 2) | Commodity Contract | Natural Gas
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	6	[2]	2	[2]
Derivative liabilities	34	[2]	54	[2]
Significant Other Observable Inputs (Level 2) | Commodity Contract | Natural Gas | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[2]	1	[2]
Derivative liabilities	5	[2]	8	[2]
Significant Other Observable Inputs (Level 2) | Commodity Contract | Natural Gas | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	5	[2]	1	[2]
Derivative liabilities	29	[2]	46	[2]
Significant Other Observable Inputs (Level 2) | Commodity Contract | Power
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[2]	2	[2]
Derivative liabilities	2	[2]	2	[2]
Significant Other Observable Inputs (Level 2) | Commodity Contract | Power | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[2]	2	[2]
Derivative liabilities	2	[2]	2	[2]
Significant Other Observable Inputs (Level 2) | Debt Securities | Corporate bonds
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	61		52
Significant Other Observable Inputs (Level 2) | Debt Securities | Corporate bonds | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	61		52
Significant Other Observable Inputs (Level 2) | Debt Securities | Municipal bonds
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	2		2
Significant Other Observable Inputs (Level 2) | Debt Securities | Municipal bonds | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	2		2
Significant Other Observable Inputs (Level 2) | Debt Securities | US treasury and government securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	94		94
Significant Other Observable Inputs (Level 2) | Debt Securities | US treasury and government securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	94		94
Significant Other Observable Inputs (Level 2) | Debt Securities | Asset-backed Securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	14		10
Significant Other Observable Inputs (Level 2) | Debt Securities | Asset-backed Securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	14		10
Significant Other Observable Inputs (Level 2) | Debt Securities | Other Debt Securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1		1
Significant Other Observable Inputs (Level 2) | Debt Securities | Other Debt Securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1		1
Significant Other Unobservable Inputs (Level 3)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets fair value	20	[2]	29	[2]
Significant Other Unobservable Inputs (Level 3) | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets fair value	20	[2]	29	[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	20	[2]	29	[2]
Derivative liabilities	134	[2]	119	[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	20	[2]	29	[2]
Derivative liabilities	14	[2]	11	[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	120	[2]	108	[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Fuel Oils
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	5	[2]	8	[2]
Derivative liabilities	4	[2]	3	[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Fuel Oils | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	5	[2]	8	[2]
Derivative liabilities	4	[2]	3	[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Natural Gas
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[2]		[2]
Derivative liabilities	1	[2]		[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Natural Gas | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[2]
Derivative liabilities	1	[2]		[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Natural Gas | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		[2]		[2]
Derivative liabilities				[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Power
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	14	[2]	21	[2]
Derivative liabilities	124	[2]	110	[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Power | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	14	[2]	21	[2]
Derivative liabilities	4	[2]	2	[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Power | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	120	[2]	108	[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Uranium
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	5	[2]	6	[2]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Uranium | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	$ 5	[2]	$ 6	[2]

[1] Balance excludes $2 million of receivables, payables, and accrued income, net.

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

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Derivative Financial Instruments

3 Months Ended

Mar. 31, 2014

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, diesel, power, and uranium. Such price fluctuations may cause the following:

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

• market values of 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 for derivative assets and liabilities as of March 31, 2014, and December 31, 2013. As of March 31, 2014, these contracts ran through October 2016, October 2019, May 2032, and October 2016 for fuel oils, natural gas, power, and uranium, respectively.

	Quantity (in millions, except as indicated)
	2014			2013
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)(a)	53	(b)	53	66	(b)	66
Natural gas (in mmbtu)	28	109	137	28	108	136
Power (in megawatthours)	2	11	13	3	11	14
Uranium (pounds in thousands)	827	(b)	827	796	(b)	796

(a) Fuel oils consist of ultra-low-sulfur diesel, on-highway diesel, and crude oil.

(b) Not applicable.

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 7 - Fair Value Measurements for a discussion of 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. 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 losses and gains 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. As of March 31, 2014, and December 31, 2013, all contracts that qualify for hedge accounting received regulatory deferral.

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, 2014, and December 31, 2013:

	Balance Sheet Location	Ameren Missouri		Ameren Illinois		Ameren
2014
Derivative assets not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current assets	$	5	$	—	$	5
	Other assets	1		—		1
Natural gas	Other current assets	1		5		6
	Other assets	1		—		1
Power	Other current assets	15		—		15
	Total assets	$	23	$	5	$	28
Derivative liabilities not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current liabilities	$	2	$	—	$	2
	Other deferred credits and liabilities	2		—		2
Natural gas	Other current liabilities	4		16		20
	Other deferred credits and liabilities	4		13		17
Power	Other current liabilities	6		8		14
	Other deferred credits and liabilities	—		112		112
Uranium	Other current liabilities	4		—		4
	Other deferred credits and liabilities	1		—		1
	Total liabilities	$	23	$	149	$	172
2013
Derivative assets not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current assets	$	6	$	—	$	6
	Other assets	3		—		3
Natural gas	Other current assets	1		1		2
Power	Other current assets	23		—		23
	Total assets	$	33	$	1	$	34
Derivative liabilities not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current liabilities	$	2	$	—	$	2
	Other deferred credits and liabilities	1		—		1
Natural gas	Other current liabilities	5		27		32
	Other deferred credits and liabilities	6		19		25
Power	Other current liabilities	4		9		13
	Other deferred credits and liabilities	—		99		99
Uranium	Other current liabilities	5		—		5
	Other deferred credits and liabilities	1		—		1
	Total liabilities	$	24	$	154	$	178

(a) Includes derivatives subject to regulatory deferral.

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments deferred as regulatory assets or regulatory liabilities as of March 31, 2014, and December 31, 2013:

	Ameren Missouri			Ameren Illinois			Ameren
2014
Cumulative gains (losses) deferred as regulatory liabilities or assets:
Fuel oils derivative contracts(a)	$	—		$	—		$	—
Natural gas derivative contracts(b)	(6		)	(24		)	(30		)
Power derivative contracts(c)	9			(120		)	(111		)
Uranium derivative contracts(d)	(5		)	—			(5		)
2013
Cumulative gains (losses) deferred as regulatory liabilities or assets:
Fuel oils derivative contracts	$	2		$	—		$	2
Natural gas derivative contracts	(10		)	(45		)	(55		)
Power derivative contracts	19			(108		)	(89		)
Uranium derivative contracts	(6		)	—			(6		)

(a) Represents net gains (losses) on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through December 2016 as of March 31, 2014. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014.

(b) Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2019 at Ameren and Ameren Missouri and through October 2017 at Ameren Illinois, in each case as of March 31, 2014. 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, 2014. Current losses deferred as regulatory assets include $20 million, $4 million, and $16 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2014.

(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, 2014. Current gains deferred as regulatory liabilities include $15 million and $15 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014. Current losses deferred as regulatory assets include $14 million, $6 million, and $8 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2014.

(d) Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through December 2016, as of March 31, 2014. Current losses deferred as regulatory assets include $4 million and $4 million at Ameren and Ameren Missouri, respectively, as of March 31, 2014.

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) the 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 the 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 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, 2014, and December 31, 2013:

			Gross Amounts Not Offset in the Balance Sheet
Commodity Contracts Eligible to be Offset	Gross Amounts Recognized in the Balance Sheet		Derivative Instruments		Cash Collateral Received/Posted(a)		Net Amount
2014
Assets:
Ameren Missouri	$	23	$	9	$	—	$	14
Ameren Illinois	5		3		—		2
Ameren	$	28	$	12	$	—	$	16
Liabilities:
Ameren Missouri	$	23	$	9	$	9	$	5
Ameren Illinois	149		3		3		143
Ameren	$	172	$	12	$	12	$	148
2013
Assets:
Ameren Missouri	$	33	$	9	$	—	$	24
Ameren Illinois	1		1		—		—
Ameren	$	34	$	10	$	—	$	24
Liabilities:
Ameren Missouri	$	24	$	9	$	9	$	6
Ameren Illinois	154		1		15		138
Ameren	$	178	$	10	$	24	$	144

(a) Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current assets” and “Other assets” on the balance sheet.

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. We calculate maximum exposures based on the gross fair value of financial instruments, including accrual and NPNS contracts. As of March 31, 2014, if counterparty groups were to fail completely to perform on contracts, Ameren, Ameren Missouri and Ameren Illinois' maximum exposure was $14 million, $9 million, and $5 million, respectively. As of December 31, 2013, if counterparty groups were to fail completely to perform on contracts, Ameren, Ameren Missouri and Ameren Illinois' maximum exposure was $13 million, $12 million, and $1 million, respectively. 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. As of March 31, 2014, the potential loss after consideration of the application of master trading and netting agreements and collateral held for Ameren, Ameren Missouri and Ameren Illinois was $5 million, $3 million, and $2 million, respectively. As of December 31, 2013, the potential loss after consideration of the application of master trading and netting agreements and collateral held for Ameren and Ameren Missouri was $6 million and $6 million, respectively.

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, 2014, and December 31, 2013, 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, 2014, or December 31, 2013, respectively, 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)
2014
Ameren Missouri	$	56	$	2	$	51
Ameren Illinois	80		3		65
Ameren	$	136	$	5	$	116
2013
Ameren Missouri	$	70	$	2	$	67
Ameren Illinois	75		15		55
Ameren	$	145	$	17	$	122

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

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Fair Value Measurements

3 Months Ended

Mar. 31, 2014

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 comprises 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 primarily 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 reasonableness review, 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 as of March 31, 2014:

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
Level 3 Derivative asset and liability - commodity contracts(a):
Ameren	Fuel oils	$	5	$	(4	)	Option model	Volatilities(%)(b)	13 - 34	16
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.25 - 0.99	0.63
	Natural gas	1		(1		)	Option model	Volatilities(%)(b)	27 - 102	40
								Nodal basis($/mmbtu)(c)	(0.3) - (0.2)	(0.2)
							Discounted cash flow	Nodal basis($/mmbtu)(c)	(0.2) - (0.1)	(0.1)
								Counterparty credit risk(%)(c)(d)	0.27 - 5	1
								Ameren Missouri credit risk(%)(c)(d)	0.43	(e)
	Power(f)	14		(124		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	27 - 57	33
								Estimated auction price for FTRs($/MW)(b)	(1,109) - 2,981	474
								Nodal basis($/MWh)(c)	(6) - (1)	(3)
								Counterparty credit risk(%)(c)(d)	0.35	(e)
								Ameren Missouri and Ameren Illinois credit risk(%)(c)(d)	0.43	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 6	5
								Escalation rate(%)(b)(g)	2 - 3	3
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6
	Uranium	—		(5		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	34 - 40	35
Ameren Missouri	Fuel oils	$	5	$	(4	)	Option model	Volatilities(%)(b)	13 - 34	16
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.25 - 0.99	0.63
	Natural gas	1		(1		)	Option model	Volatilities(%)(b)	27 - 102	40
								Nodal basis($/mmbtu)(c)	(0.3) - (0.2)	(0.2)
							Discounted cash flow	Nodal basis($/mmbtu)(c)	(0.2) - (0.1)	(0.1)
								Counterparty credit risk(%)(c)(d)	0.27 - 5	1
								Ameren Missouri credit risk(%)(c)(d)	0.43	(e)
	Power(f)	14		(4		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	30 - 57	45
								Estimated auction price for FTRs($/MW)(b)	(1,109) - 2,981	474
								Nodal basis($/MWh)(c)	(3) - (1)	(2)
								Counterparty credit risk(%)(c)(d)	0.35	(e)
								Ameren Missouri credit risk(%)(c)(d)	0.43	(e)
	Uranium	—		(5		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	34 - 40	35
Ameren Illinois	Power(f)	$	—	$	(120	)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b)	27 - 40	32
								Nodal basis($/MWh)(b)	(6) - (1)	(3)
								Ameren Illinois credit risk(%)(c)(d)	0.43	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 6	5
								Escalation rate(%)(b)(g)	2 - 3	3
							Contract price allocation	Estimated renewable energy credit costs($/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 applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances.

(e) Not applicable.

(f) Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2018. Valuations beyond 2018 use fundamentally modeled pricing by month for peak and off-peak demand.

(g) Escalation rate applies to power prices 2026 and beyond.

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 as of December 31, 2013:

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
Level 3 Derivative asset and liability – commodity contracts(a):
Ameren	Fuel oils	$	8	$	(3	)	Option model	Volatilities(%)(b)	10 - 35	16
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.26 - 2	1
	Power(e)	21		(110		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	25 - 51	32
								Estimated auction price for FTRs($/MW)(b)	(1,594) - 945	305
								Nodal basis($/MWh)(c)	(3) - (1)	(2)
								Counterparty credit risk(%)(c)(d)	0.39 - 0.50	0.42
								Ameren Missouri and Ameren Illinois credit risk(%)(c)(d)	2	(f)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 5	5
								Escalation rate(%)(b)(g)	3 - 4	4
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6
	Uranium	—		(6		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	34 - 41	36
Ameren Missouri	Fuel oils	$	8	$	(3	)	Option model	Volatilities(%)(b)	10 - 35	16
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.26 - 2	1
	Power(e)	21		(2		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	25 - 51	40
								Estimated auction price for FTRs($/MW)(b)	(1,594) - 945	305
								Nodal basis($/MWh)(c)	(3) - (1)	(2)
								Counterparty credit risk(%)(c)(d)	0.39 - 0.50	0.42
								Ameren Missouri credit risk(%)(c)(d)	2	(f)
	Uranium	—		(6		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	34 - 41	36
Ameren Illinois	Power(e)	$	—	$	(108	)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b)	27 - 36	30
								Nodal basis($/MWh)(b)	(4) - 0	(2)
								Ameren Illinois credit risk(%)(c)(d)	2	(f)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 5	5
								Escalation rate(%)(b)(g)	3 - 4	4
							Contract price allocation	Estimated renewable energy credit costs($/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 applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances.

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

(f) Not applicable.

(g) Escalation rate applies to power prices 2026 and beyond.

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. No gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri or Ameren Illinois in the first three months of 2014 or 2013. At March 31, 2014, 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, 2013, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $3 million, less than $1 million, and $3 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, 2014:

		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	$	1	$	—	$	5	$	6
	Natural gas	—		6		1		7
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	1	$	7	$	20	$	28
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	327		—		—		327
	Debt securities:
	Corporate bonds	—		61		—		61
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		94		—		94
	Asset-backed securities	—		14		—		14
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	329	$	172	$	—	$	501	(b)
	Total Ameren	$	330	$	179	$	20	$	529
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	1	$	—	$	5	$	6
	Natural gas	—		1		1		2
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	1	$	2	$	20	$	23
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	327		—		—		327
	Debt securities:
	Corporate bonds	—		61		—		61
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		94		—		94
	Asset-backed securities	—		14		—		14
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	329	$	172	$	—	$	501	(b)
	Total Ameren Missouri	$	330	$	174	$	20	$	524
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	—	$	5	$	—	$	5
Liabilities:
Ameren	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	—	$	—	$	4	$	4
	Natural gas	2		34		1		37
	Power	—		2		124		126
	Uranium	—		—		5		5
	Total Ameren	$	2	$	36	$	134	$	172
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	—	$	—	$	4	$	4
	Natural gas	2		5		1		8
	Power	—		2		4		6
	Uranium	—		—		5		5
	Total Ameren Missouri	$	2	$	7	$	14	$	23
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	29	$	—	$	29
	Power	—		—		120		120
	Total Ameren Illinois	$	—	$	29	$	120	$	149

(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 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, 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	$	1	$	—	$	8	$	9
	Natural gas	—		2		—		2
	Power	—		2		21		23
	Total derivative assets - commodity contracts	$	1	$	4	$	29	$	34
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	3	$	—	$	—	$	3
	Equity securities:
	U.S. large capitalization	332		—		—		332
	Debt securities:
	Corporate bonds	—		52		—		52
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		94		—		94
	Asset-backed securities	—		10		—		10
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	335	$	159	$	—	$	494
	Total Ameren	$	336	$	163	$	29	$	528
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	1	$	—	$	8	$	9
	Natural gas	—		1		—		1
	Power	—		2		21		23
	Total derivative assets - commodity contracts	$	1	$	3	$	29	$	33
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	3	$	—	$	—	$	3
	Equity securities:
	U.S. large capitalization	332		—		—		332
	Debt securities:
	Corporate bonds	—		52		—		52
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		94		—		94
	Asset-backed securities	—		10		—		10
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	335	$	159	$	—	$	494
	Total Ameren Missouri	$	336	$	162	$	29	$	527
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	—	$	1	$	—	$	1
Liabilities:
Ameren	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	—	$	—	$	3	$	3
	Natural gas	3		54		—		57
	Power	—		2		110		112
	Uranium	—		—		6		6
	Total Ameren	$	3	$	56	$	119	$	178
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	—	$	—	$	3	$	3
	Natural gas	3		8		—		11
	Power	—		2		2		4
	Uranium	—		—		6		6
	Total Ameren Missouri	$	3	$	10	$	11	$	24
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	46	$	—	$	46
	Power	—		—		108		108
	Total Ameren Illinois	$	—	$	46	$	108	$	154

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

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, 2014:

		Net derivative commodity contracts
Three Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2014	$	5		$	(a)		$	5
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(2	)		(a)			(2	)
Settlements		(2	)		(a)			(2	)
Ending balance at March 31, 2014	$	1		$	(a)		$	1
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2014	$	(1	)	$	(a)		$	(1	)
Natural gas:
Beginning balance at January 1, 2014	$	—		$	—		$	—
Purchases		—			(2	)		(2	)
Settlements		—			2			2
Ending balance at March 31, 2014	$	—		$	—		$	—
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2014	$	—		$	—		$	—
Power:
Beginning balance at January 1, 2014	$	19		$	(108	)	$	(89	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(5	)		(12	)		(17	)
Settlements		(5	)		—			(5	)
Transfers out of Level 3		1			—			1
Ending balance at March 31, 2014	$	10		$	(120	)	$	(110	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2014	$	(1	)	$	(14	)	$	(15	)
Uranium:
Beginning balance at January 1, 2014	$	(6	)	$	(a)		$	(6	)
Settlements		1			(a)			1
Ending balance at March 31, 2014	$	(5	)	$	(a)		$	(5	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2014	$	—		$	(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, 2013:

		Net derivative commodity contracts
Three Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2013	$	5		$	(a)		$	5
Purchases		1			(a)			1
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
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
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	)
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.

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 between Level 2 and Level 3 for power derivatives were primarily caused by changes in availability of financial trades observable on electronic exchanges between the periods shown below. 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, 2014, and 2013, 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, 2014, and 2013:

	Three Months
	2014						2013
Derivative commodity contracts	Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri			Ameren Illinois		Ameren
Transfers into Level 3 / Transfers out of Level 2 - Power	$	—	$	—	$	—	$	(2	)	$	—	$	(2	)
Transfers out of Level 3 / Transfers into Level 2 - Power	1		—		1		1			—		1
Net fair value of Level 3 transfers	$	1	$	—	$	1	$	(1	)	$	—	$	(1	)

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. The Ameren Companies’ short-term borrowings 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, capital lease obligations and preferred stock at March 31, 2014, and December 31, 2013:

	March 31, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:(a)
Long-term debt and capital lease obligations (including current portion)	$	5,874	$	6,530	$	6,038	$	6,584
Preferred stock	142		119		142		118
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	3,758	$	4,200	$	3,757	$	4,124
Preferred stock	80		71		80		71
Ameren Illinois:
Long-term debt (including current portion)	$	1,692	$	1,903	$	1,856	$	2,028
Preferred stock	62		48		62		47

(a) Preferred stock is recorded in “Noncontrolling Interests” on the consolidated balance sheet.

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Commitments And Contingencies

3 Months Ended

Mar. 31, 2014

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, authorities 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, Note 15 - Commitments and Contingencies and Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions, Note 10 - Callaway Energy Center and Note 12 - Divestiture Transactions and Discontinued Operations in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at March 31, 2014. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year. Both coverages were renewed in 2014.

Type and Source of Coverage	Maximum  Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	375		$	—
Pool participation	13,241		(a)	128		(b)
	$	13,616	(c)	$	128
Property damage:
NEIL	$	2,250	(d)	$	23	(e)
European Mutual Association for Nuclear Insurance	500		(f)	—
	$	2,750		$	23
Replacement power:
NEIL	$	490	(g)	$	9	(e)
Missouri Energy Risk Assurance Company LLC	64		(h)	—

(a) Provided through mandatory participation in an industrywide retrospective premium assessment program.

(b) Retrospective premium under the Price-Anderson Act. 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 $19 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 $128 million per incident for each licensed reactor it operates with a maximum of $19 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) NEIL provides $2.25 billion in property damage, decontamination, and premature decommissioning insurance. There is a $1.7 billion sublimit for nonradiation events, of which the last $200 million is a shared limit with other generators purchasing this coverage. The $1.7 billion sublimit for nonradiation events was not included with the April 1, 2014 renewal.

(e) All NEIL insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL.

(f) European Mutual Association for Nuclear Insurance provides $500 million in excess of the $2.25 billion property coverage provided by NEIL.

(g) Provides 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. Nonradiation events are sub-limited to $327.6 million.

(h) Provides 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 NEIL and is a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 8 - Related Party Transactions for more information on this affiliate transaction.

The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. 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 was effective September 10, 2013. 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 the Price-Anderson Act.

Losses resulting from terrorist attacks are covered under NEIL’s policies, subject to an industrywide 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, 2014, 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 $6,251 million, $4,273 million, and $1,908 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 generation, 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, discharges to water, water usage, impacts to air, land, and water, and chemical and waste handling. Complex and lengthy processes are required to obtain and renew approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures.

The EPA is developing environmental regulations that will have a significant impact on the electric utility industry. Over time, compliance with these regulations could be particularly costly for certain companies, including Ameren Missouri, that operate coal-fired energy centers. Significant new rules proposed or promulgated include the regulation of CO₂ emissions from new energy centers; revised national ambient air quality standards for ozone, fine particulates, SO_2, and NO_x emissions; the CSAPR, which requires 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 waste water discharges from energy centers and new regulations under the Clean Water Act that could require significant capital expenditures, such as modifications to water intake structures or new cooling towers at our energy centers. The EPA is expected to propose CO₂ standards for existing fossil fuel-fired electric generation 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. 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 increased operating costs over the next five to ten years for Ameren and Ameren Missouri. Compliance with these environmental laws and regulations could be prohibitively expensive or could result in the closure or alteration of the operation of some of our energy centers. Ameren and Ameren Missouri would expect these costs to be recoverable through rates, but the nature and timing of costs, as well as the applicable regulatory framework, could result in regulatory lag.

As of March 31, 2014, Ameren and Ameren Missouri estimate capital expenditure investments of $275 million to $350 million over the next five years to comply with existing environmental regulations. This estimate assumes that CCR will continue to be regulated as nonhazardous. This estimate does not include the impacts of regulations proposed by the EPA under the Clean Water Act regarding cooling water intake structures or the impact of the proposed effluent standards applicable to steam-electric generating units, as the technology requirements of these final rules are not yet known. Considerable uncertainty remains in this estimate. The actual amount of capital expenditure investments to comply with existing environmental regulations may vary substantially from the above estimate due to uncertainty as to the precise compliance strategies that will be used and their ultimate cost, among other things.

Ameren Missouri's current environmental compliance plan for air emissions includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. Ameren Missouri has two scrubbers at its Sioux energy center, which are used to reduce SO₂ emissions and other pollutants. Currently, Ameren Missouri's compliance plan assumes the installation of additional controls including mercury control technology and electrostatic precipitator upgrades at multiple energy centers within its coal-fired fleet during the next five years. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the CSAPR, the MATS, and other recently finalized or proposed EPA regulations. Ameren Missouri may be required to install additional pollution controls within the next six to ten years.

Environmental compliance costs at some of Ameren Missouri's energy centers could be prohibitive and additional capital investment or continued operations unwarranted. Ameren Missouri's capital expenditures and other costs are subject to MoPSC prudence reviews, which could result in cost disallowances as well as regulatory lag.

The following sections describe the more significant environmental laws and 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 2005, the EPA issued regulations with respect to SO₂ and NO_x emissions (the CAIR). In December 2008, the United States Court of Appeals for the District of Columbia Circuit found various aspects of the law to be unlawful and remanded the CAIR to the EPA for further action, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. The CSAPR regulations were vacated by the United States Court of Appeals for the District of Columbia Circuit. The EPA appealed to the United States Supreme Court. In April 2014, the United States Supreme Court reversed the decision of the United States Court of Appeals for the District of Columbia Circuit’s decision and upheld the CSAPR. Ameren and Ameren Missouri are continuing to review the United States Supreme Court’s decision and expect the EPA to issue guidance in the near future on implementing the CSAPR. Ameren Missouri has already taken actions to prepare for the implementation of the CSAPR, including the installation of two scrubbers at its Sioux energy center and burning ultra-low sulfur coal. Assuming the EPA does not revise the emission reductions previously included in the CSAPR, Ameren Missouri does not expect to make additional capital investments to comply with the CSAPR. However, Ameren Missouri will incur additional operations and maintenance costs to utilize chemicals to lower its emissions at one or more of its energy centers for compliance with the CSAPR. These higher operations and maintenance costs will be collected from customers through the FAC or higher base rates.

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 hydrogen chloride emissions. 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 April 2016 to comply with the MATS.

Emission Allowances

The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NO_x budget trading program, the CAIR and the CSAPR. Ameren Missouri expects to have enough allowances for 2014 to avoid making external purchases to comply with the CAIR and the acid rain program. Ameren and Ameren Missouri are continuing to review the United States Supreme Court’s decision upholding the CSAPR and will review any guidance the EPA may issue regarding implementing the CSAPR and its emission allowance program.

Greenhouse Gas Regulation

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 permit upon renewal. Currently, all Ameren energy centers have operating permits that have been modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources or new 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 to control greenhouse gas emissions. 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. In October 2013, the United States Supreme Court agreed to consider whether the Clean Air Act authorizes the EPA to regulate emissions of greenhouse gases from stationary sources, including power plants, as a result of its determination to regulate greenhouse gas emissions from motor vehicles. A ruling is expected in 2014.

In June 2013, the Obama administration announced that it had directed the EPA to set CO₂ emissions standards for both new and existing power plants. The EPA published proposed regulations in January 2014 that would set revised CO₂ emissions standards for new electricity generating units. The proposed standards would establish separate emissions limits for new natural gas-fired plants and new coal-fired plants. In addition, the Obama administration directed the EPA to propose a CO₂ emissions standard for existing power plants by June 2014 and to finalize such standard by June 2015. Currently, Ameren and Ameren Missouri are unable to predict the outcome of these rulemakings or impacts of such future regulations if and when they become effective.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases may result in significant increases in capital expenditures and operating costs, which could lead to increased liquidity needs and higher financing costs. These 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 if costs are not recovered through rates. Mandatory limits on the emission of greenhouse gases could increase costs for our customers or have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity if regulators delay or deny cost recovery in rates of these compliance costs. Ameren's and Ameren Missouri's earnings may benefit from increased investment to the extent the investments comply with greenhouse gas limitations and are reflected and recovered timely in rates.

NSR and Clean Air Litigation

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, as amended in October 2013, alleges that in performing projects at its Rush Island coal-fired energy center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the district court granted, in part, Ameren Missouri's motion to dismiss various aspects of the EPA's penalty claims. The EPA's claims for unspecified injunctive relief remain. The trial in this matter is currently scheduled to begin in 2015. Ameren Missouri believes its defenses are meritorious and will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.

Ultimate resolution of this matter could have a material adverse effect 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. The proposed rule would impose standards for reducing the mortality of aquatic organisms impinged on the plant's intake screens or entrained through the plant's cooling water system. All coal-fired, nuclear, and combined cycle energy centers at Ameren Missouri with cooling water systems are subject to this proposed rule. The EPA has stated that it will finalize the rule in May 2014. When finalized, the rule could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers or extensive modifications to the cooling water systems at our energy centers and if those investments are not recovered timely in rates.

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 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 the rule is enacted as proposed, Ameren Missouri would be subject to the revised limitations beginning as early as July 1, 2017, but no later than July 1, 2022, however, the final rule will determine the schedule. The EPA expects to issue final guidelines by September 30, 2015.

Ash Management

In May 2010, the EPA announced proposed new regulations regarding 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. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric generating units would apply to ash ponds and CCR management and that it intended to align this proposal with the CCR rules when finalized. The EPA is expected to issue regulations describing how it will regulate CCR by December 2014. Ameren Missouri is 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 Missouri is 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.

Remediation

We are involved in a number of remediation actions to clean up sites impacted by hazardous substances 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 at several contaminated sites.

As of March 31, 2014, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois. These sites 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 incurred. Costs are subject to annual review by the ICC.

As of March 31, 2014, 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.

The following table presents, as of March 31, 2014, the estimated obligation to complete the remediation of these former MGP sites:

	Estimate				Recorded   Liability(a)
	Low		High
Ameren	$	269	$	345	$	269
Ameren Missouri	3		4		3
Ameren Illinois	266		341		266

(a) Recorded liability represents the estimated minimum probable obligations, as no other amount within the range was 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 used an off-site landfill, which Ameren Illinois did not own, in connection with the former operation of an energy center. Ameren Illinois could be required to perform certain maintenance activities associated with that landfill. As of March 31, 2014, 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 some underground storage tanks and a water treatment plant in Illinois. As of March 31, 2014, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.

Ameren Missouri is investigating and addressing 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. While Ameren Missouri is the current owner of the site, it did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other potentially responsible parties, are performing a site investigation. As of March 31, 2014, 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 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 investigation and 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 therefore, Ameren Missouri believes it has no liability at March 31, 2014, 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 potentially responsible parties to evaluate the extent of potential contamination with respect to Sauget Area 2.

In December 2013, the EPA issued its record of decision for Sauget Area 2 approving the investigation and the remediation alternatives recommended by the potentially responsible parties. Further negotiation among the potentially responsible parties will determine how to fund the implementation of the EPA approved cleanup remedies. As of March 31, 2014, Ameren Missouri estimated its obligation related to Sauget Area 2 at $1 million to $2.5 million. During the first quarter of 2014, Ameren Missouri recorded an additional liability of $0.7 million, to reflect the negotiations with the potentially responsible parties, for a total liability of $1 million to represent its estimated minimum obligation.

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, 2014, Ameren Missouri estimated the obligation related to the cleanup at $1.6 million to $4.5 million. Ameren Missouri recorded a liability of $1.6 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.

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, 2014, Ameren Missouri had an insurance receivable balance of $68 million.

In June 2010, Ameren Missouri sued an insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed that the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In January 2011, the district court ruled that the parties must first pursue alternative dispute resolution and enforced the forum selection clause of their coverage agreement. The forum selection clause requires use of New York law and effectively requires mandatory arbitration. 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 public policy voids the forum selection clause. In September 2013, the district court ruled that Missouri public policy voids the forum selection clause.

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, which is pending in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. The insurance company filed a motion to compel arbitration, which the district court denied. In April 2013, the United States Court of Appeals for the Eighth Circuit affirmed the district court’s denial of the insurer’s motion and remanded the case to the district court.

Ameren's and Ameren Missouri's results of operations, financial position and liquidity could be adversely affected if Ameren Missouri's remaining liability insurance claims are not paid by insurers.

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 at our present or former energy centers. 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 85 as of March 31, 2014. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.

The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of March 31, 2014:

Ameren	Ameren Missouri	Ameren Illinois	Total(a)
1	47	56	71

(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, 2014, Ameren, Ameren Missouri and Ameren Illinois had liabilities of $12 million, $5 million, and $7 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 IP 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, 2014, 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. The rider will permit recovery 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 2,400 accounts, primarily in annexed areas, for the period 2004 through 2012. In July 2013, the O’Fallon city administrator issued an order stating that Ameren Illinois was liable to the city of O’Fallon for $4 million. In August 2013, Ameren Illinois filed an appeal and a stay of the O’Fallon city administrator’s order to the Circuit Court of St. Clair County. In addition, in December 2012, the city of Peoria issued a tax liability notice alleging that Ameren Illinois failed to collect prior-period municipal taxes from certain accounts. In September 2013, a hearing officer issued an order stating that Ameren Illinois was liable to the city of Peoria for $0.5 million. Ameren Illinois filed an appeal and a stay of the order to the Circuit Court of Peoria County. Ameren Illinois believes its defenses to the allegations are meritorious. As of March 31, 2014, Ameren Illinois estimated its obligation at $1 million to $5 million. Ameren Illinois recorded a liability of $1 million, which reflects potential settlements with both of the cities.

In addition, at the end of 2012, five other cities issued tax liability notices alleging that Ameren Illinois failed to collect an immaterial amount of taxes from certain accounts.

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Related Party Transactions (Schedule of Related Party Transactions) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Union Electric Company
Related Party Transaction [Line Items]
Operating Revenues	$ 5		$ 6
Operating Expenses	33		31
Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Revenues	1	[1]	1	[1]
Operating Expenses	27		25
Purchased Power | Union Electric Company
Related Party Transaction [Line Items]
Operating Expenses	1	[2]	1	[2]
Purchased Power | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Expenses	1		2
Ameren Missouri Power Supply Agreements with Ameren Illinois | Union Electric Company
Related Party Transaction [Line Items]
Operating Revenues	1	[1]	1
Ameren Missouri Power Supply Agreements with Ameren Illinois | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Revenues	1	[2]	1	[2]
Ameren Missouri and Ameren Illinois Rent and Facility Services | Union Electric Company
Related Party Transaction [Line Items]
Operating Revenues	5		5
Ameren Missouri and Ameren Illinois Rent and Facility Services | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Revenues	1	[1]	1	[1]
Ameren Illinois Power Supply Agreements with Ameren Missouri | Union Electric Company
Related Party Transaction [Line Items]
Operating Expenses	1	[2]	1	[2]
Ameren Illinois Power Supply Agreements with Ameren Missouri | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Expenses	1	[1]	1
Ameren Illinois Transmission Agreements with ATXI [Member] | Union Electric Company
Related Party Transaction [Line Items]
Operating Expenses	1	[2]	1	[2]
Ameren Illinois Transmission Agreements with ATXI [Member] | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Expenses	1		1
Ameren Services Support Services Agreement | Union Electric Company
Related Party Transaction [Line Items]
Operating Expenses	33		31
Ameren Services Support Services Agreement | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Expenses	27		25
Insurance Premiums | Union Electric Company
Related Party Transaction [Line Items]
Operating Expenses	1	[1],[3]	1	[1],[3]
Insurance Premiums | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Expenses	1	[2],[3]	1	[2],[3]
Related Party Money Pool Interest | Union Electric Company
Related Party Transaction [Line Items]
Interest Charges	1	[1]	1	[1]
Related Party Money Pool Interest | Ameren Illinois Company
Related Party Transaction [Line Items]
Interest Charges	$ 1	[1]	$ 1	[1]

[1] Amount less than $1 million.

[2] Not applicable.

[3] Represents insurance premiums paid to Missouri Energy Risk Assurance Company LLC, 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, 2014
Long-term Purchase Commitment [Line Items]
Other obligations	$ 6,251
Union Electric Company
Long-term Purchase Commitment [Line Items]
Other obligations	4,273
Ameren Illinois Company
Long-term Purchase Commitment [Line Items]
Other obligations	$ 1,908

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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, 2014		Dec. 31, 2013
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	$ 6,530	[1]	$ 6,584	[1]
Preferred stock	119	[1]	118	[1]
Fair Value | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	4,200		4,124
Preferred stock	71		71
Fair Value | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	1,903		2,028
Preferred stock	48		47
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	5,874	[1]	6,038	[1]
Preferred stock	142	[1]	142	[1]
Carrying Amount | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	3,758		3,757
Preferred stock	80		80
Carrying Amount | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	1,692		1,856
Preferred stock	$ 62		$ 62

[1] Preferred stock is recorded in “Noncontrolling Interests” on the consolidated balance sheet.

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Schedule Of Segment Reporting Information By Segment

The following table presents information about the reported revenues and specified items reflected in Ameren’s net income attributable to Ameren Corporation from continuing operations for the three months ended March 31, 2014, and 2013, and total assets in continuing operations as of March 31, 2014, and December 31, 2013.

Three Months	Ameren Missouri		Ameren Illinois		Other			Intersegment Eliminations			Ameren
2014
External revenues	$	811	$	774	$	9		$	—		$	1,594
Intersegment revenues	6		—		1			(7		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	47		53		(3		)	—			97
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
As of March 31, 2014:
Total assets	$	12,948	$	7,640	$	898		$	(335	)	$	21,151	(a)
As of December 31, 2013:
Total assets	$	12,904	$	7,454	$	752		$	(233	)	$	20,877	(a)

(a)    Excludes total assets from discontinued operations of $15 million and $165 million as of March 31, 2014, and December 31, 2013, respectively.

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Derivative Financial Instruments (Open Gross Derivative Volumes By Commodity Type) (Detail)	Mar. 31, 2014 gal		Dec. 31, 2013 gal
Fuel Oils
Derivative [Line Items]
Quantity	53,000,000	[1]	66,000,000	[1]
Natural Gas
Derivative [Line Items]
Quantity	137,000,000		136,000,000
Power
Derivative [Line Items]
Quantity	13,000,000		14,000,000
Uranium
Derivative [Line Items]
Quantity	827,000		796,000
Union Electric Company | Fuel Oils
Derivative [Line Items]
Quantity	53,000,000	[1]	66,000,000	[1]
Union Electric Company | Natural Gas
Derivative [Line Items]
Quantity	28,000,000		28,000,000
Union Electric Company | Power
Derivative [Line Items]
Quantity	2,000,000		3,000,000
Union Electric Company | Uranium
Derivative [Line Items]
Quantity	827,000		796,000
Ameren Illinois Company | Natural Gas
Derivative [Line Items]
Quantity	109,000,000		108,000,000
Ameren Illinois Company | Power
Derivative [Line Items]
Quantity	11,000,000		11,000,000

[1] Fuel oils consist of ultra-low-sulfur diesel, on-highway diesel, and crude oil.

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Summary Of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Consolidation

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. Ameren Missouri and Ameren Illinois have no subsidiaries, and therefore their financial statements are not prepared on a consolidated basis. 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, 2014, and 2013, caused by the assumed settlement of performance share units. The number of dilutive performance share units had an immaterial impact on earnings per share.

Stock-based Compensation

Ameren’s long-term incentive plan available for eligible employees, the 2006 Omnibus Incentive Compensation Plan (2006 Plan), was replaced prospectively for new grants only by the 2014 Omnibus Incentive Compensation Plan (2014 Plan) effective April 24, 2014. The 2014 Plan provides for a maximum of 8 million common shares to be available for grant to eligible employees and directors, and retains many of the features of the 2006 Plan. The 2014 Plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards.

Intangible Assets

Ameren and Ameren Missouri classify renewable energy credits and emission allowances 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, 2014, 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 $17 million each at March 31, 2014. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $22 million each at December 31, 2013.

Ameren Missouri’s and Ameren Illinois’ renewable energy credits and Ameren Missouri’s 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 customer and are therefore not included in revenues and expenses. They are included in “Taxes accrued” on the balance sheet.

Uncertain Tax Positions

Ameren’s federal income tax returns for the years 2007 through 2011 are before the Appeals Office of the IRS. Ameren’s federal income tax return for the year 2012 is currently under examination.

It is reasonably possible that a settlement will be reached with the Appeals Office of the IRS in the next 12 months for the years 2007 through 2011. This settlement, which is primarily related to uncertain tax positions for research tax deductions, is expected to result in a decrease in uncertain tax benefits of $20 million and $13 million for Ameren and Ameren Missouri, 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.

With the adoption of new accounting guidance in the first quarter of 2014, unrecognized tax benefits are recorded in “Accumulated deferred income taxes, net” as a reduction to the deferred tax assets for net operating loss and tax credit carryforwards on Ameren’s, Ameren Missouri’s and Ameren Illinois’ balance sheets. Unrecognized tax benefits that exceed these carryforwards are recorded in “Other deferred credits and liabilities” on the respective balance sheets. At March 31, 2014, unrecognized tax benefits of $84 million, $14 million, and $- million were recorded in “Accumulated deferred income taxes, net” on Ameren's, Ameren Missouri's and Ameren Illinois' balance sheets, respectively. At December 31, 2013, unrecognized tax benefits of $84 million, $15 million, and $- million previously recorded in “Other deferred credits and liabilities” on the respective balance sheets were reclassified to “Accumulated deferred income taxes, net” for comparative purposes.

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri and Ameren Illinois increased at March 31, 2014, compared to December 31, 2013, to reflect the accretion of obligations to their fair value, partially offset by immaterial settlements.

Noncontrolling Interest

As of March 31, 2014, Ameren's noncontrolling interests were composed of the preferred stock not subject to mandatory redemption of Ameren Missouri and Ameren Illinois. All noncontrolling interests are classified as a component of equity separate from Ameren's equity on its consolidated balance sheet.

Accounting and Reporting Developments

The following is a summary of recently adopted authoritative accounting guidance.

Presentation of an Unrecognized Tax Benefit

In July 2013, FASB issued additional authoritative accounting guidance to provide clarity for the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The objective of this guidance is to eliminate diversity in practice related to the presentation of certain unrecognized tax benefits. It requires entities to present an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward to the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is available under the tax law. This guidance was effective for the Ameren Companies beginning in the first quarter of 2014. Previously, unrecognized tax benefits were recorded in “Other deferred credits and liabilities” on Ameren's, Ameren Missouri's and Ameren Illinois' balance sheets. Beginning in the first quarter 2014, unrecognized tax benefits are recorded in “Accumulated deferred income taxes, net” as a reduction to the deferred tax assets for net operating loss and tax credit carryforwards on the respective balance sheets. Unrecognized tax benefits that exceed these carryforwards are recorded in “Other deferred credits and liabilities,” on the respective balance sheets. For comparative purposes, the Ameren Companies reclassified the December 31, 2013 balances in accordance with the new guidance as discussed in the Uncertain Tax Positions section above. The implementation of the additional authoritative accounting guidance did not affect the Ameren Companies' results of operations or liquidity, as this guidance is presentation-related only.

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Long-Term Debt And Equity Financings (Tables)

3 Months Ended

Mar. 31, 2014

Long-Term Debt And Equity Financings [Line Items]

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, 2014, at an assumed annual 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	$	4,018		≥2.5	118.8	$	2,272
Ameren Illinois	≥2.0	7.6		3,732	(d)	≥1.5	2.7		203	(e)

(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 $729 million and $454 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 Illinois Company

Long-Term Debt And Equity Financings [Line Items]

Debt Instrument Redemption [Table Text Block]

In January 2014, Ameren Illinois redeemed the following environmental improvement and pollution control revenue bonds at par value plus accrued interest:

Environmental improvement and pollution control revenue bonds	Principal Amount
5.90% Series 1993 due 2023(a)	$	32
5.70% 1994A Series due 2024(a)	36
1993 Series C-1 5.95% due 2026	35
1993 Series C-2 5.70% due 2026	8
5.40% 1998A Series due 2028	19
5.40% 1998B Series due 2028	33
Total amount redeemed	$	163

(a) Less than $1 million principal amount of the bonds remain outstanding after redemption.

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Long-Term Debt And Equity Financings (Schedule Of Covered Ratio) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Union Electric Company
Long-Term Debt And Equity Financings [Line Items]
Bonds Issuable	$ 4,018	[1]
Preferred Stock Issuable	2,272
Retired bond capacity	729
Union Electric Company | Actual Ratio [Member]
Long-Term Debt And Equity Financings [Line Items]
Restricted payment interest coverage ratio, Actual	4.7
Dividend Coverage Ratio	118.8
Ameren Illinois Company
Long-Term Debt And Equity Financings [Line Items]
Bonds Issuable	3,732	[1],[2]
Preferred Stock Issuable	203	[3]
Retired bond capacity	$ 454
Ameren Illinois Company | Actual Ratio [Member]
Long-Term Debt And Equity Financings [Line Items]
Restricted payment interest coverage ratio, Actual	7.6
Dividend Coverage Ratio	2.7
Minimum | Union Electric Company | Minimum Required Ratio [Member]
Long-Term Debt And Equity Financings [Line Items]
Restricted payment interest coverage ratio, Actual	2.0	[4]
Dividend Coverage Ratio	2.5	[5]
Minimum | Ameren Illinois Company | Minimum Required Ratio [Member]
Long-Term Debt And Equity Financings [Line Items]
Restricted payment interest coverage ratio, Actual	2.0	[4]
Dividend Coverage Ratio	1.5	[5]

[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 $729 million and $454 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] Preferred stock issuable is restricted by the amount of preferred stock that is currently authorized by Ameren Illinois’ articles of incorporation.

[4] 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.

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

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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, 2014	Mar. 31, 2013		Dec. 31, 2013 Electric Energy, Inc
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Noncontrolling interest, beginning of period	$ 142	$ 151	[1]
Net income from continuing operations attributable to noncontrolling interests	2	2
Dividends paid to noncontrolling interest holders	(2)	(2)
Noncontrolling interest, end of period	$ 142	$ 151	[1]
Percentage of EEI not owned by Ameren				20.00%

[1] Included the 20% EEI ownership interest not owned by Ameren prior to the divestiture of New AER to IPH. Prior to the divestiture of New AER, the assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Assets of discontinued operations” and “Liabilities of discontinued operations.” The divestiture of New AER, which included EEI, was completed in the fourth quarter of 2013. See Note 12 - Divestiture Transactions and Discontinued Operations for additional information.

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Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Current Assets:
Cash and cash equivalents	$ 26	$ 30
Accounts receivable - trade (less allowance for doubtful accounts)	553	404
Unbilled revenue	236	304
Miscellaneous accounts and notes receivable	201	196
Materials and supplies	424	526
Current regulatory assets	220	156
Current accumulated deferred income taxes, net	95	106
Other current assets	70	85
Assets of discontinued operations (Note 12)	15	165
Total current assets	1,840	1,972
Property and Plant, Net	16,425	16,205
Investments and Other Assets:
Nuclear decommissioning trust fund	503	494
Goodwill	411	411
Intangible assets	17	22
Regulatory assets	1,251	1,240
Other assets	719	698
Total investments and other assets	2,901	2,865
TOTAL ASSETS	21,166	21,042
Current Liabilities:
Current maturities of long-term debt	648	534
Short-term Debt	700	368
Accounts and wages payable	559	806
Taxes accrued	89	55
Interest accrued	104	86
Current regulatory liabilities	248	216
Other current liabilities	344	351
Liabilities of discontinued operations (Note 12)	33	45
Total current liabilities	2,725	2,461
Long-term Debt, Net	5,226	5,504
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	3,340	3,250
Accumulated deferred investment tax credits	62	63
Regulatory liabilities	1,751	1,705
Asset retirement obligations	373	369
Pension and other postretirement benefits	480	466
Other deferred credits and liabilities	554	538
Total deferred credits and other liabilities	6,560	6,391
Commitments and Contingencies
Stockholders' Equity:
Common Stock	2	2
Other paid-in capital	5,602	5,632
Retained earnings	906	907
Accumulated other comprehensive income (loss)	3	3
Stockholder's equity	6,513	6,544
Noncontrolling Interest	142	142
Total equity	6,655	6,686
TOTAL LIABILITIES AND EQUITY	21,166	21,042
Union Electric Company
Current Assets:
Cash and cash equivalents		1
Accounts receivable - trade (less allowance for doubtful accounts)	218	191
Accounts receivable - affiliates	1	1
Unbilled revenue	129	168
Miscellaneous accounts and notes receivable	67	57
Materials and supplies	338	352
Current regulatory assets	145	118
Other current assets	50	71
Total current assets	948	959
Property and Plant, Net	10,499	10,452
Investments and Other Assets:
Nuclear decommissioning trust fund	503	494
Intangible assets	17	22
Regulatory assets	539	534
Other assets	442	443
Total investments and other assets	1,501	1,493
TOTAL ASSETS	12,948	12,904
Current Liabilities:
Current maturities of long-term debt	223	109
Short-term Debt	290
Borrowings from money pool		105
Accounts and wages payable	183	387
Accounts payable - affiliates	38	30
Taxes accrued	252	220
Interest accrued	47	57
Current regulatory liabilities	47	57
Other current liabilities	87	82
Total current liabilities	1,167	1,047
Long-term Debt, Net	3,535	3,648
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	2,551	2,524
Accumulated deferred investment tax credits	58	59
Regulatory liabilities	1,062	1,041
Asset retirement obligations	371	366
Pension and other postretirement benefits	198	189
Other deferred credits and liabilities	43	37
Total deferred credits and other liabilities	4,283	4,216
Commitments and Contingencies
Stockholders' Equity:
Common Stock	511	511
Other paid-in capital	1,560	1,560
Preferred stock not subject to mandatory redemption	80	80
Retained earnings	1,812	1,842
Stockholder's equity	3,963	3,993
TOTAL LIABILITIES AND EQUITY	12,948	12,904
Ameren Illinois Company
Current Assets:
Cash and cash equivalents	1	1
Accounts receivable - trade (less allowance for doubtful accounts)	328	201
Unbilled revenue	107	135
Miscellaneous accounts and notes receivable	8	13
Materials and supplies	86	174
Current regulatory assets	75	38
Current accumulated deferred income taxes, net	52	45
Other current assets	20	26
Total current assets	677	633
Property and Plant, Net	5,731	5,589
Investments and Other Assets:
Goodwill	411	411
Regulatory assets	706	701
Other assets	115	120
Total investments and other assets	1,232	1,232
TOTAL ASSETS	7,640	7,454
Current Liabilities:
Borrowings from money pool	242	56
Accounts and wages payable	230	243
Accounts payable - affiliates	28	18
Taxes accrued	22	23
Customer deposits	80	79
Current environmental remediation	46	43
Current regulatory liabilities	201	159
Other current liabilities	153	150
Total current liabilities	1,002	771
Long-term Debt, Net	1,692	1,856
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,158	1,116
Accumulated deferred investment tax credits	4	4
Regulatory liabilities	689	664
Pension and other postretirement benefits	200	197
Environmental remediation	222	232
Other deferred credits and liabilities	173	166
Total deferred credits and other liabilities	2,446	2,379
Commitments and Contingencies
Stockholders' Equity:
Common Stock	0	0
Other paid-in capital	1,965	1,965
Preferred stock not subject to mandatory redemption	62	62
Retained earnings	463	410
Accumulated other comprehensive income (loss)	10	11
Stockholder's equity	2,500	2,448
TOTAL LIABILITIES AND EQUITY	$ 7,640	$ 7,454

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Short-Term Debt And Liquidity

3 Months Ended

Mar. 31, 2014

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 credit agreements, or commercial paper issuances.

The 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement, both of which expire on November 14, 2017, were not utilized for direct borrowings during the three months ended March 31, 2014, but they were used to support commercial paper issuances and to issue letters of credit. As of March 31, 2014, based on letters of credit issued under the 2012 Credit Agreements, as well as commercial paper outstanding, the aggregate amount of credit capacity available to Ameren (parent), Ameren Missouri and Ameren Illinois, collectively, at March 31, 2014, was $1.4 billion.

Commercial Paper

Ameren (parent) had $410 million and $368 million of commercial paper outstanding at March 31, 2014, and December 31, 2013, respectively. Ameren Missouri had $290 million and $- million of commercial paper outstanding at March 31, 2014, and December 31, 2013, respectively.

The following table summarizes the commercial paper activity and relevant interest rates under Ameren’s (parent) and Ameren Missouri’s commercial paper programs for the three months ended March 31, 2014, and 2013:

	Ameren (parent)			Ameren Missouri			Ameren Consolidated
2014
Average daily commercial paper outstanding	$	339		$	200		$	539
Weighted-average interest rate	0.45		%	0.45		%	0.45		%
Peak commercial paper during period(a)	$	452		$	290		$	700
Peak interest rate	0.75		%	0.70		%	0.75		%
2013
Average daily commercial paper outstanding	$	2		$	—		$	2
Weighted-average interest rate	0.80		%	—		%	0.80		%
Peak commercial paper during period(a)	$	21		$	—		$	21
Peak interest rate	0.85		%	—		%	0.85		%

(a) The timing of peak commercial paper issuances varies by company, and therefore the amounts presented by company might not equal the Ameren Consolidated peak commercial paper issuances for the period.

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 under Part II, Item 8, 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, 2014, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2012 Credit Agreements, were 50%, 49% and 44%, 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 at least 2.0 to 1.0, 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, 2014, was 5.6 to 1.0. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2012 Credit Agreement. The calculation of Ameren’s ratios discussed above includes both continuing and discontinued operations.

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. The Ameren Companies were in compliance with the provisions and covenants of their credit agreements at March 31, 2014.

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. Ameren Services is responsible for the operation and administration of the money pool agreements.

Ameren Missouri, Ameren Illinois and Ameren Services may participate in the utility money pool as both lenders and borrowers. Ameren may participate in the money pools only as a lender. Surplus internal funds are contributed to the money pool from participants. The primary sources of external funds for the money pool are the 2012 Credit Agreements and the commercial paper programs. The total amount available to the pool participants from the 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 money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. Participants receiving a loan under the 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 money pool. The average interest rate for borrowing under the utility money pool for the three months ended March 31, 2014, was 0.39% (2013 - 0.11%).

See Note 8 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three months ended March 31, 2014, and 2013.

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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, 2014		Dec. 31, 2013
Natural Gas | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Counterparty credit risk	0.27%	[1],[2]
Nodal basis	(0.20)	[1]
Credit risk	0.43%	[1],[2]
Natural Gas | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Counterparty credit risk	5.00%	[1],[2]
Nodal basis	(0.1)	[1]
Credit risk	0.43%	[1],[2]
Natural Gas | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Counterparty credit risk	1.00%	[1],[2]
Nodal basis	(0.1)	[1]
Credit risk	0.43%	[1],[2]
Natural Gas | Option Model | Minimum
Fair Value Inputs [Abstract]
Volatilities	27.00%	[3]
Nodal basis	(0.30)	[1]
Natural Gas | Option Model | Maximum
Fair Value Inputs [Abstract]
Volatilities	102.00%	[3]
Nodal basis	(0.20)	[1]
Natural Gas | Option Model | Weighted Average
Fair Value Inputs [Abstract]
Volatilities	40.00%	[3]
Nodal basis	(0.20)	[1]
Natural Gas | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	$ 1	[4]
Natural Gas | Union Electric Company | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Counterparty credit risk	0.27%	[1],[2]
Nodal basis	(0.20)	[1]
Credit risk	0.43%	[1],[2]
Natural Gas | Union Electric Company | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Counterparty credit risk	5.00%	[1],[2]
Nodal basis	(0.1)	[1]
Credit risk	0.43%	[1],[2]
Natural Gas | Union Electric Company | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Counterparty credit risk	1.00%	[1],[2]
Nodal basis	(0.1)	[1]
Credit risk	0.43%	[1],[2]
Natural Gas | Union Electric Company | Option Model | Minimum
Fair Value Inputs [Abstract]
Escalation rate
Volatilities	27.00%	[3]
Nodal basis	(0.30)	[1]
Natural Gas | Union Electric Company | Option Model | Maximum
Fair Value Inputs [Abstract]
Escalation rate
Volatilities	102.00%	[3]
Nodal basis	(0.20)	[1]
Natural Gas | Union Electric Company | Option Model | Weighted Average
Fair Value Inputs [Abstract]
Escalation rate
Volatilities	40.00%	[3]
Nodal basis	(0.20)	[1]
Natural Gas | Union Electric Company | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	1	[4]
Natural Gas | Ameren Illinois Company | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets		[4]
Natural Gas | Derivative Liabilities
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(1)	[4]
Natural Gas | Derivative Liabilities | Union Electric Company
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(1)	[4]
Natural Gas | Derivative Liabilities | Ameren Illinois Company
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities		[4]
Fuel Oils | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Counterparty credit risk	0.25%	[1],[2]	0.26%	[1],[2]
Fuel Oils | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Counterparty credit risk	0.99%	[1],[2]	2.00%	[1],[2]
Fuel Oils | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Counterparty credit risk	0.63%	[1],[2]	1.00%	[1],[2]
Fuel Oils | Option Model | Minimum
Fair Value Inputs [Abstract]
Volatilities	13.00%	[3]	10.00%	[3]
Fuel Oils | Option Model | Maximum
Fair Value Inputs [Abstract]
Volatilities	34.00%	[3]	35.00%	[3]
Fuel Oils | Option Model | Weighted Average
Fair Value Inputs [Abstract]
Volatilities	16.00%	[3]	16.00%	[3]
Fuel Oils | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	5	[4]	8	[4]
Fuel Oils | Union Electric Company | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Counterparty credit risk	0.25%	[1],[2]	0.26%	[1],[2]
Fuel Oils | Union Electric Company | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Counterparty credit risk	0.99%	[1],[2]	2.00%	[1],[2]
Fuel Oils | Union Electric Company | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Counterparty credit risk	0.63%	[1],[2]	1.00%	[1],[2]
Fuel Oils | Union Electric Company | Option Model | Minimum
Fair Value Inputs [Abstract]
Volatilities	13.00%	[3]	10.00%	[3]
Fuel Oils | Union Electric Company | Option Model | Maximum
Fair Value Inputs [Abstract]
Volatilities	34.00%	[3]	35.00%	[3]
Fuel Oils | Union Electric Company | Option Model | Weighted Average
Fair Value Inputs [Abstract]
Volatilities	16.00%	[3]	16.00%	[3]
Fuel Oils | Union Electric Company | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	5	[4]	8	[4]
Fuel Oils | Derivative Liabilities
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(4)	[4]	(3)	[4]
Fuel Oils | Derivative Liabilities | Union Electric Company
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(4)	[4]	(3)	[4]
Power | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Counterparty credit risk	0.35%	[1],[2]	0.39%	[1],[2]
Nodal basis	(6)	[1]	(3)	[1]
Credit risk	0.43%	[1],[2]	2.00%	[1],[2]
Average forward peak and off-peak pricing	27	[1]	25	[1]
Estimated auction price	(1,109)	[3]	(1,594)	[3]
Power | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Counterparty credit risk	0.35%	[1],[2]	0.50%	[1],[2]
Nodal basis	(1)	[1]	(1)	[1]
Credit risk	0.43%	[1],[2]	2.00%	[1],[2]
Average forward peak and off-peak pricing	57	[1]	51	[1]
Estimated auction price	2,981	[3]	945	[3]
Power | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Counterparty credit risk	0.35%	[1],[2]	0.42%	[1],[2]
Nodal basis	(3)	[1]	(2)	[1]
Credit risk	0.43%	[1],[2]	2.00%	[1],[2]
Average forward peak and off-peak pricing	33	[1]	32	[1]
Estimated auction price	474	[3]	305	[3]
Power | Fundamental Energy Production Model | Minimum
Fair Value Inputs [Abstract]
Escalation rate	2.00%	[3],[5]	3.00%	[3],[5]
Estimated future gas prices	4	[3]	4	[3]
Power | Fundamental Energy Production Model | Maximum
Fair Value Inputs [Abstract]
Escalation rate	3.00%	[3],[5]	4.00%	[3],[5]
Estimated future gas prices	6	[3]	5	[3]
Power | Fundamental Energy Production Model | Weighted Average
Fair Value Inputs [Abstract]
Escalation rate	3.00%	[3],[5]	4.00%	[3],[5]
Estimated future gas prices	5	[3]	5	[3]
Power | Contract Price Allocation | Minimum
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	5	[3]	5	[3]
Power | Contract Price Allocation | Maximum
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	7	[3]	7	[3]
Power | Contract Price Allocation | Weighted Average
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	6	[3]	6	[3]
Power | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	14	[4],[6]	21	[4],[7]
Power | Union Electric Company | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Counterparty credit risk	0.35%	[1],[2]	0.39%	[1],[2]
Nodal basis	(3)	[1]	(3)	[1]
Credit risk	0.43%	[1],[2]	2.00%	[1],[2]
Average forward peak and off-peak pricing	30	[1]	25	[1]
Estimated auction price	(1,109)	[3]	(1,594)	[3]
Power | Union Electric Company | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Counterparty credit risk	0.35%	[1],[2]	0.50%	[1],[2]
Nodal basis	(1)	[1]	(1)	[1]
Credit risk	0.43%	[1],[2]	2.00%	[1],[2]
Average forward peak and off-peak pricing	57	[1]	51	[1]
Estimated auction price	2,981	[3]	945	[3]
Power | Union Electric Company | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Counterparty credit risk	0.35%	[1],[2]	0.42%	[1],[2]
Nodal basis	(2)	[1]	(2)	[1]
Credit risk	0.43%	[1],[2]	2.00%	[1],[2]
Average forward peak and off-peak pricing	45	[1]	40	[1]
Estimated auction price	474	[3]	305	[3]
Power | Union Electric Company | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	14	[4],[6]	21	[4],[7]
Power | Ameren Illinois Company | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Nodal basis	(6)	[3]	(4)	[3]
Credit risk	0.43%	[1],[2]	2.00%	[1],[2]
Average forward peak and off-peak pricing	27	[3]	27	[3]
Power | Ameren Illinois Company | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Nodal basis	(1)	[3]	0	[3]
Credit risk	0.43%	[1],[2]	2.00%	[1],[2]
Average forward peak and off-peak pricing	40	[3]	36	[3]
Power | Ameren Illinois Company | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Nodal basis	(3)	[3]	(2)	[3]
Credit risk	0.43%	[1],[2]	2.00%	[1],[2]
Average forward peak and off-peak pricing	32	[3]	30	[3]
Power | Ameren Illinois Company | Fundamental Energy Production Model | Minimum
Fair Value Inputs [Abstract]
Escalation rate	2.00%	[3],[5]	3.00%	[3],[5]
Estimated future gas prices	4	[3]	4	[3]
Power | Ameren Illinois Company | Fundamental Energy Production Model | Maximum
Fair Value Inputs [Abstract]
Escalation rate	3.00%	[3],[5]	4.00%	[3],[5]
Estimated future gas prices	6	[3]	5	[3]
Power | Ameren Illinois Company | Fundamental Energy Production Model | Weighted Average
Fair Value Inputs [Abstract]
Escalation rate	3.00%	[3],[5]	4.00%	[3],[5]
Estimated future gas prices	5	[3]	5	[3]
Power | Ameren Illinois Company | Contract Price Allocation | Minimum
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	5	[3]	5	[3]
Power | Ameren Illinois Company | Contract Price Allocation | Maximum
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	7	[3]	7	[3]
Power | Ameren Illinois Company | Contract Price Allocation | Weighted Average
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	6	[3]	6	[3]
Power | Ameren Illinois Company | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets		[4],[6]		[4],[7]
Power | Derivative Liabilities
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(124)	[4],[6]	(110)	[4],[7]
Power | Derivative Liabilities | Union Electric Company
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(4)	[4],[6]	(2)	[4],[7]
Power | Derivative Liabilities | Ameren Illinois Company
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(120)	[4],[6]	(108)	[4],[7]
Uranium | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Average forward pricing	34	[3]	34	[3]
Uranium | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Average forward pricing	40	[3]	41	[3]
Uranium | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Average forward pricing	35	[3]	36	[3]
Uranium | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets		[4]		[4]
Uranium | Union Electric Company | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Average forward pricing	34	[3]	34	[3]
Uranium | Union Electric Company | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Average forward pricing	40	[3]	41	[3]
Uranium | Union Electric Company | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Average forward pricing	35	[3]	36	[3]
Uranium | Union Electric Company | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets		[4]		[4]
Uranium | Derivative Liabilities
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	(5)	[4]	(6)	[4]
Uranium | Derivative Liabilities | Union Electric Company
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	$ (5)	[4]	$ (6)	[4]

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

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

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

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

[5] Escalation rate applies to power prices 2026 and beyond.

[6] Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2018. Valuations beyond 2018 use fundamentally modeled pricing by month for peak and off-peak demand.

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

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Commitments And Contingencies (Asbestos-Related Litigation And Tax Exemptions And Credits) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended						1 Months Ended
	Mar. 31, 2014 Asbestos-Related defendant lawsuit		Mar. 31, 2014 Asbestos-Related Union Electric Company lawsuit	Mar. 31, 2014 Asbestos-Related Ameren Illinois Company lawsuit	Mar. 31, 2014 Asbestos-Related Ameren Corporation lawsuit	Mar. 31, 2014 Collectibility of Taxes Ameren Illinois Company customer	Sep. 30, 2013 State and Local Jurisdiction [Member] Collectibility of Taxes Ameren Illinois Company	Jul. 31, 2013 State and Local Jurisdiction [Member] Collectibility of Taxes Ameren Illinois Company
Loss Contingencies [Line Items]
Average number of total defendants named	85
Asbestos-related lawsuits were pending	71	[1]	47	56	1
Range of possible loss, minimum	$ 12.0		$ 5.0	$ 7.0		$ 1.0
Range of possible loss maximum						5.0
Loss contingency accrual						1
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%
Public Utilities, Number of Customers						2,400
Loss Contingency, Damages Awarded, Value							$ 0.5	$ 4.0

[1] 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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Other Income and Expenses (Tables)

3 Months Ended

Mar. 31, 2014

Other Nonoperating Income (Expense) [Abstract]

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, 2014, and 2013:

	Three Months
	2014		2013
Ameren:(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	7	$	8
Interest income on industrial development revenue bonds	7		7
Interest and dividend income	2		—
Other	2		—
Total miscellaneous income	$	18	$	15
Miscellaneous expense:
Donations	$	5	$	4
Other	4		4
Total miscellaneous expense	$	9	$	8
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	7	$	7
Interest income on industrial development revenue bonds	7		7
Total miscellaneous income	$	14	$	14
Miscellaneous expense:
Donations	$	2	$	2
Other	2		3
Total miscellaneous expense	$	4	$	5
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	—	$	1
Interest and dividend income	2		—
Other	1		—
Total miscellaneous income	$	3	$	1
Miscellaneous expense:
Donations	$	3	$	3
Other	1		—
Total miscellaneous expense	$	4	$	3

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

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Divestiture Transactions and Discontinued Operations (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			3 Months Ended					1 Months Ended	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Mar. 31, 2013 New Ameren Energy Resources Company, LLC	Mar. 31, 2014 New Ameren Energy Resources Company, LLC	Mar. 14, 2013 New Ameren Energy Resources Company, LLC	Mar. 31, 2014 Notes Payable, Other Payables [Member] New Ameren Energy Resources Company, LLC	Dec. 31, 2013 Notes Payable, Other Payables [Member] New Ameren Energy Resources Company, LLC	Jan. 31, 2014 Elgin, Gibson City and Grand Tower Energy Centers	Dec. 31, 2013 Elgin, Gibson City and Grand Tower Energy Centers	Mar. 31, 2014 Ameren Energy Marketing Company [Member]	Mar. 31, 2014 Guarantee Type, Other [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Escrow Deposit, Reserve Period	2 years
Proceeds from Sales of Business, Affiliate and Productive Assets									$ 168.0	$ 137.5
Proceeds from Asset Sale Held in Escrow									17
Impairment of assets to be disposed of				155
Discontinued operations deferred tax expense				98
Discontinued operations deferred tax benefit				63
Loss from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	1	199
Asset retirement obligations	373		369
Range of possible loss maximum					34.0
Other deferred credits and liabilities	554		538		29
Accounts and wages payable	559		806		5
Notes, Loans and Financing Receivable, Net, Noncurrent							27	18
Buyer's indemnification guarantee obligation						25
Guarantees Outstanding	184										171	13
Guarantees, Maximum Exposure											17
Letters of Credit Outstanding, Amount	$ 9

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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, 2014	Mar. 31, 2013
Accounting Policies [Line Items]
Excise tax expense	$ 60	$ 55
Union Electric Company
Accounting Policies [Line Items]
Excise tax expense	34	33
Ameren Illinois Company
Accounting Policies [Line Items]
Excise tax expense	$ 26	$ 22

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Segment Information

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

Ameren has two reportable segments: Ameren Missouri and Ameren Illinois. The Ameren Missouri segment for both Ameren and Ameren Missouri includes all of 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 category called Other primarily includes Ameren parent company activities, Ameren Services, and ATXI. In 2013, the Other category also included certain corporate activities previously included in the Merchant Generation segment.

The following table presents information about the reported revenues and specified items reflected in Ameren’s net income attributable to Ameren Corporation from continuing operations for the three months ended March 31, 2014, and 2013, and total assets in continuing operations as of March 31, 2014, and December 31, 2013.

Three Months	Ameren Missouri		Ameren Illinois		Other			Intersegment Eliminations			Ameren
2014
External revenues	$	811	$	774	$	9		$	—		$	1,594
Intersegment revenues	6		—		1			(7		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	47		53		(3		)	—			97
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
As of March 31, 2014:
Total assets	$	12,948	$	7,640	$	898		$	(335	)	$	21,151	(a)
As of December 31, 2013:
Total assets	$	12,904	$	7,454	$	752		$	(233	)	$	20,877	(a)

(a)    Excludes total assets from discontinued operations of $15 million and $165 million as of March 31, 2014, and December 31, 2013, respectively.