Union Electric (UEPEP) 10-Q 2014 Q3 Quarterly report

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 September 30, 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 October 31, 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 - 102,123,834
Ameren Illinois Company	Common stock, no par value, held by Ameren Corporation - 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	3
	Consolidated Statement of Comprehensive Income	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	50
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	70
Item 4.	Controls and Procedures	72
PART II Other Information
Item 1.	Legal Proceedings	73
Item 1A.	Risk Factors	73
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	73
Item 6.	Exhibits	73
Signatures		75

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.

2006 Incentive Plan - The 2006 Omnibus Incentive Compensation Plan, which became effective in May 2006 and provided for compensatory stock-based awards to eligible employees and directors. The 2006 Omnibus Incentive Compensation Plan was replaced prospectively for new grants by the 2014 Incentive Plan.

2014 Incentive Plan - The 2014 Omnibus Incentive Compensation Plan, which became effective in April 2014 and provides for compensatory stock-based awards to eligible employees and directors.

Clean Power Plan - “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units,” a proposed rule issued by the EPA on June 18, 2014.

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.

Net energy cost - Net energy cost, as defined in the FAC, includes fuel and purchased power costs, including transportation charges and revenues, net of off-system sales.

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 Ameren Missouri’s July 2014 electric rate case filing; Ameren Illinois' appeals of the ICC's electric and natural gas

rate orders issued in December 2013; Ameren Illinois’ April 2014 annual electric delivery service formula update filing; FERC settlement procedures regarding a potential Ameren Illinois electric transmission rate refund; 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 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 potential extension of the IEIMA after its current sunset provision at the end of 2017, and any changes to the performance-based formula ratemaking process or required financial commitments;

• 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 customer energy efficiency and distributed generation sources, which generate electricity at the site of consumption;

• the effectiveness of Ameren Missouri’s energy efficiency programs and the ability to earn incentive awards under the MEEIA;

• the timing of 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 have an adverse effect on the cost or availability of capital, including short-term credit and liquidity;

• our assessment of our liquidity;

1

• 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 claim against an insurer in connection with its Taum Sauk pumped-storage hydroelectric energy center incident;

• the extent to which Ameren Missouri is permitted by its regulators to recover in rates the investments it made in connection with additional nuclear generation at its Callaway energy center;

• operation of Ameren Missouri's Callaway energy center, including planned 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 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 or investment requirements, 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, mortality tables, 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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Operating Revenues:
Electric	$	1,523		$	1,507		$	3,864		$	3,823
Gas	147			131			819			693
Total operating revenues	1,670			1,638			4,683			4,516
Operating Expenses:
Fuel	236			222			638			648
Purchased power	112			128			335			400
Gas purchased for resale	49			42			432			344
Other operations and maintenance	404			383			1,236			1,229
Depreciation and amortization	187			175			551			528
Taxes other than income taxes	121			121			362			354
Total operating expenses	1,109			1,071			3,554			3,503
Operating Income	561			567			1,129			1,013
Other Income and Expense:
Miscellaneous income	21			20			60			51
Miscellaneous expense	7			5			20			18
Total other income	14			15			40			33
Interest Charges	85			88			266			289
Income Before Income Taxes	490			494			903			757
Income Taxes	194			187			357			288
Income from Continuing Operations	296			307			546			469
Loss from Discontinued Operations, Net of Taxes (Note 12)	(1		)	(3		)	(3		)	(212		)
Net Income	295			304			543			257
Less: Net Income from Continuing Operations Attributable to Noncontrolling Interests	2			2			5			5
Net Income (Loss) Attributable to Ameren Corporation:
Continuing Operations	294			305			541			464
Discontinued Operations	(1		)	(3		)	(3		)	(212		)
Net Income Attributable to Ameren Corporation	$	293		$	302		$	538		$	252
Earnings (Loss) per Common Share – Basic:
Continuing Operations	$	1.21		$	1.26		$	2.23		$	1.92
Discontinued Operations	—			(0.01		)	(0.01		)	(0.88		)
Earnings per Common Share – Basic	$	1.21		$	1.25		$	2.22		$	1.04
Earnings (Loss) per Common Share – Diluted:
Continuing Operations	$	1.20		$	1.25		$	2.21		$	1.91
Discontinued Operations	—			(0.01		)	(0.01		)	(0.88		)
Earnings per Common Share – Diluted	$	1.20		$	1.24		$	2.20		$	1.03
Dividends per Common Share	$	0.40		$	0.40		$	1.20		$	1.20
Average Common Shares Outstanding – Basic	242.6			242.6			242.6			242.6
Average Common Shares Outstanding – Diluted	244.3			245.1			244.3			244.4

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

3

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Unaudited) (In millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Income from Continuing Operations	$	296		$	307		$	546		$	469
Other Comprehensive Income (Loss), Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $-, $(5), $3 and $3, respectively	—			(5		)	3			5
Comprehensive Income from Continuing Operations	296			302			549			474
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests	2			2			5			5
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation	294			300			544			469
Loss from Discontinued Operations, Net of Taxes	(1		)	(3		)	(3		)	(212		)
Other Comprehensive Loss from Discontinued Operations, Net of Taxes	—			(5		)	—			(16		)
Comprehensive Loss from Discontinued Operations Attributable to Ameren Corporation	(1		)	(8		)	(3		)	(228		)
Comprehensive Income Attributable to Ameren Corporation	$	293		$	292		$	541		$	241

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)

	September 30, 2014		December 31, 2013
ASSETS
Current Assets:
Cash and cash equivalents	$	13	$	30
Accounts receivable – trade (less allowance for doubtful accounts of $21 and $18, respectively)	467		404
Unbilled revenue	203		304
Miscellaneous accounts and notes receivable	117		196
Materials and supplies	561		526
Current regulatory assets	199		156
Current accumulated deferred income taxes, net	301		106
Other current assets	66		85
Assets of discontinued operations (Note 12)	15		165
Total current assets	1,942		1,972
Property and Plant, Net	16,991		16,205
Investments and Other Assets:
Nuclear decommissioning trust fund	529		494
Goodwill	411		411
Intangible assets	20		22
Regulatory assets	1,259		1,240
Other assets	724		698
Total investments and other assets	2,943		2,865
TOTAL ASSETS	$	21,876	$	21,042
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	119	$	534
Short-term debt	753		368
Accounts and wages payable	466		806
Taxes accrued	161		55
Interest accrued	105		86
Current regulatory liabilities	132		216
Other current liabilities	350		351
Liabilities of discontinued operations (Note 12)	33		45
Total current liabilities	2,119		2,461
Long-term Debt, Net	5,825		5,504
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	3,845		3,250
Accumulated deferred investment tax credits	59		63
Regulatory liabilities	1,805		1,705
Asset retirement obligations	385		369
Pension and other postretirement benefits	400		466
Other deferred credits and liabilities	522		538
Total deferred credits and other liabilities	7,016		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	5,612		5,632
Retained earnings	1,154		907
Accumulated other comprehensive income	6		3
Total Ameren Corporation stockholders’ equity	6,774		6,544
Noncontrolling Interests	142		142
Total equity	6,916		6,686
TOTAL LIABILITIES AND EQUITY	$	21,876	$	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)
	Nine Months Ended September 30,
	2014			2013
Cash Flows From Operating Activities:
Net income	$	543		$	257
Loss from discontinued operations, net of taxes	3			212
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	526			500
Amortization of nuclear fuel	70			46
Amortization of debt issuance costs and premium/discounts	16			18
Deferred income taxes and investment tax credits, net	370			258
Allowance for equity funds used during construction	(26		)	(26		)
Stock-based compensation costs	20			19
Other	(9		)	14
Changes in assets and liabilities:
Receivables	16			(88		)
Materials and supplies	(34		)	7
Accounts and wages payable	(187		)	(102		)
Taxes accrued	100			104
Assets, other	(123		)	20
Liabilities, other	(70		)	(24		)
Pension and other postretirement benefits	(27		)	(34		)
Counterparty collateral, net	20			34
Net cash provided by operating activities – continuing operations	1,208			1,215
Net cash provided by (used in) operating activities – discontinued operations	(5		)	99
Net cash provided by operating activities	1,203			1,314
Cash Flows From Investing Activities:
Capital expenditures	(1,310		)	(943		)
Nuclear fuel expenditures	(28		)	(34		)
Purchases of securities – nuclear decommissioning trust fund	(365		)	(147		)
Sales and maturities of securities – nuclear decommissioning trust fund	354			134
Proceeds from note receivable – Marketing Company	79			—
Contributions to note receivable – Marketing Company	(84		)	—
Other	3			(1		)
Net cash used in investing activities – continuing operations	(1,351		)	(991		)
Net cash provided by (used in) investing activities – discontinued operations	139			(42		)
Net cash used in investing activities	(1,212		)	(1,033		)
Cash Flows From Financing Activities:
Dividends on common stock	(291		)	(291		)
Dividends paid to noncontrolling interest holders	(5		)	(5		)
Short-term debt, net	385			—
Redemptions and maturities of long-term debt	(692		)	—
Issuances of long-term debt	598			—
Capital issuance costs	(4		)	—
Other	1			—
Net cash used in financing activities – continuing operations	(8		)	(296		)
Net cash used in financing activities – discontinued operations	—			—
Net cash used in financing activities	(8		)	(296		)
Net change in cash and cash equivalents	(17		)	(15		)
Cash and cash equivalents at beginning of year	30			209
Cash and cash equivalents at end of period	13			194
Less cash and cash equivalents at end of period – discontinued operations	���			25
Cash and cash equivalents at end of period – continuing operations	$	13		$	169

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 September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Operating Revenues:
Electric	$	1,076	$	1,075	$	2,696	$	2,667
Gas	21		17		117		110
Other	—		1		1		1
Total operating revenues	1,097		1,093		2,814		2,778
Operating Expenses:
Fuel	236		222		638		648
Purchased power	25		33		86		100
Gas purchased for resale	7		4		58		52
Other operations and maintenance	228		212		677		686
Depreciation and amortization	118		114		351		338
Taxes other than income taxes	89		91		248		247
Total operating expenses	703		676		2,058		2,071
Operating Income	394		417		756		707
Other Income and Expense:
Miscellaneous income	15		16		45		44
Miscellaneous expense	4		2		10		10
Total other income	11		14		35		34
Interest Charges	53		43		159		159
Income Before Income Taxes	352		388		632		582
Income Taxes	129		149		234		217
Net Income	223		239		398		365
Other Comprehensive Income	—		—		—		—
Comprehensive Income	$	223	$	239	$	398	$	365
Net Income	$	223	$	239	$	398	$	365
Preferred Stock Dividends	1		1		3		3
Net Income Available to Common Stockholder	$	222	$	238	$	395	$	362

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)

	September 30, 2014		December 31, 2013
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable – trade (less allowance for doubtful accounts of $7 and $5, respectively)	261		191
Accounts receivable – affiliates	12		1
Unbilled revenue	134		168
Miscellaneous accounts and notes receivable	86		57
Materials and supplies	350		352
Current regulatory assets	137		118
Other current assets	40		71
Total current assets	1,021		959
Property and Plant, Net	10,660		10,452
Investments and Other Assets:
Nuclear decommissioning trust fund	529		494
Intangible assets	20		22
Regulatory assets	539		534
Other assets	410		443
Total investments and other assets	1,498		1,493
TOTAL ASSETS	$	13,179	$	12,904
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	119	$	109
Borrowings from money pool	—		105
Short-term debt	65		—
Accounts and wages payable	189		387
Accounts payable – affiliates	32		30
Taxes accrued	200		220
Interest accrued	66		57
Current regulatory liabilities	11		57
Other current liabilities	99		82
Total current liabilities	781		1,047
Long-term Debt, Net	3,885		3,648
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	2,656		2,524
Accumulated deferred investment tax credits	55		59
Regulatory liabilities	1,107		1,041
Asset retirement obligations	383		366
Pension and other postretirement benefits	147		189
Other deferred credits and liabilities	44		37
Total deferred credits and other liabilities	4,392		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	1,970		1,842
Total stockholders’ equity	4,121		3,993
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	13,179	$	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)

	Nine Months Ended September 30,
	2014			2013
Cash Flows From Operating Activities:
Net income	$	398		$	365
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	329			313
Amortization of nuclear fuel	70			46
FAC prudence review charge	—			26
Amortization of debt issuance costs and premium/discounts	5			6
Deferred income taxes and investment tax credits, net	139			62
Allowance for equity funds used during construction	(24		)	(22		)
Other	1			1
Changes in assets and liabilities:
Receivables	(76		)	(148		)
Materials and supplies	3			27
Accounts and wages payable	(151		)	(124		)
Taxes accrued	(22		)	260
Assets, other	(10		)	59
Liabilities, other	6			(78		)
Pension and other postretirement benefits	(8		)	(12		)
Net cash provided by operating activities	660			781
Cash Flows From Investing Activities:
Capital expenditures	(548		)	(480		)
Nuclear fuel expenditures	(28		)	(34		)
Money pool advances, net	—			24
Purchases of securities – nuclear decommissioning trust fund	(365		)	(147		)
Sales and maturities of securities – nuclear decommissioning trust fund	354			134
Other	(6		)	(3		)
Net cash used in investing activities	(593		)	(506		)
Cash Flows From Financing Activities:
Dividends on common stock	(268		)	(320		)
Dividends on preferred stock	(3		)	(3		)
Short-term debt, net	65			—
Money pool borrowings, net	(105		)	—
Maturities of long-term debt	(104		)	—
Issuances of long-term debt	350			—
Capital issuance costs	(2		)	—
Net cash used in financing activities	(67		)	(323		)
Net change in cash and cash equivalents	—			(48		)
Cash and cash equivalents at beginning of year	1			148
Cash and cash equivalents at end of period	$	1		$	100

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

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

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014			2013
Operating Revenues:
Electric	$	445	$	432	$	1,162		$	1,160
Gas	127		115		703			585
Other	—		—		—			2
Total operating revenues	572		547		1,865			1,747
Operating Expenses:
Purchased power	89		96		256			303
Gas purchased for resale	43		38		374			292
Other operations and maintenance	185		166		580			538
Depreciation and amortization	66		59		193			182
Taxes other than income taxes	31		30		109			102
Total operating expenses	414		389		1,512			1,417
Operating Income	158		158		353			330
Other Income and Expense:
Miscellaneous income	4		4		12			7
Miscellaneous expense	2		3		7			7
Total other income	2		1		5			—
Interest Charges	31		31		90			96
Income Before Income Taxes	129		128		268			234
Income Taxes	54		51		110			93
Net Income	75		77		158			141
Other Comprehensive Loss, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(1), $(1), $(2) and $(2), respectively	—		—		(2		)	(2		)
Comprehensive Income	$	75	$	77	$	156		$	139
Net Income	$	75	$	77	$	158		$	141
Preferred Stock Dividends	—		—		2			2
Net Income Available to Common Stockholder	$	75	$	77	$	156		$	139

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)

BALANCE SHEET

(Unaudited) (In millions)

	September 30, 2014		December 31, 2013
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable – trade (less allowance for doubtful accounts of $14 and $13, respectively)	192		201
Accounts receivable – affiliates	2		—
Unbilled revenue	69		135
Miscellaneous accounts receivable	6		13
Materials and supplies	211		174
Current regulatory assets	62		38
Current accumulated deferred income taxes, net	125		45
Other current assets	17		26
Total current assets	685		633
Property and Plant, Net	6,030		5,589
Investments and Other Assets:
Goodwill	411		411
Regulatory assets	712		701
Other assets	145		120
Total investments and other assets	1,268		1,232
TOTAL ASSETS	$	7,983	$	7,454
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	189	$	—
Borrowings from money pool	16		56
Accounts and wages payable	212		243
Accounts payable – affiliates	28		18
Taxes accrued	16		23
Customer deposits	71		79
Current environmental remediation	53		43
Current regulatory liabilities	121		159
Other current liabilities	148		150
Total current liabilities	854		771
Long-term Debt, Net	1,940		1,856
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,330		1,116
Accumulated deferred investment tax credits	3		4
Regulatory liabilities	698		664
Pension and other postretirement benefits	189		197
Environmental remediation	202		232
Other deferred credits and liabilities	165		166
Total deferred credits and other liabilities	2,587		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	566		410
Accumulated other comprehensive income	9		11
Total stockholders’ equity	2,602		2,448
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	7,983	$	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)

	Nine Months Ended September 30,
	2014			2013
Cash Flows From Operating Activities:
Net income	$	158		$	141
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	190			178
Amortization of debt issuance costs and premium/discounts	10			11
Deferred income taxes and investment tax credits, net	136			120
Other	(6		)	(7		)
Changes in assets and liabilities:
Receivables	80			66
Materials and supplies	(37		)	(20		)
Accounts and wages payable	1			31
Taxes accrued	(5		)	(2		)
Assets, other	(102		)	(33		)
Liabilities, other	(31		)	1
Pension and other postretirement benefits	(12		)	(13		)
Counterparty collateral, net	14			34
Net cash provided by operating activities	396			507
Cash Flows From Investing Activities:
Capital expenditures	(633		)	(462		)
Other	6			6
Net cash used in investing activities	(627		)	(456		)
Cash Flows From Financing Activities:
Dividends on common stock	—			(45		)
Dividends on preferred stock	(2		)	(2		)
Short-term debt, net	189			—
Money pool borrowings, net	(40		)	(3		)
Redemptions of long-term debt	(163		)	—
Issuances of long-term debt	248			—
Capital issuance costs	(2		)	—
Other	1			—
Net cash provided by (used in) financing activities	231			(50		)
Net change in cash and cash equivalents	—			1
Cash and cash equivalents at beginning of year	1			—
Cash and cash equivalents at end of period	$	1		$	1

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)

September 30, 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 parent company 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 constructing 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

Basic earnings per share is computed by dividing net income attributable to Ameren Corporation common stockholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income attributable to common stockholders by the diluted weighted-average number of common shares outstanding during the period. Diluted earnings per share reflects the potential dilution that would occur if certain stock-based performance share units were settled.

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The following table presents Ameren’s basic and diluted earnings per share calculations and reconciles the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the three and nine months ended September 30, 2014, and 2013:

	Three Months						Nine Months
	2014			2013			2014			2013
Net income (loss) attributable to Ameren Corporation:
Continuing operations	$	294		$	305		$	541		$	464
Discontinued operations	(1		)	(3		)	(3		)	(212		)
Net income attributable to Ameren Corporation	$	293		$	302		$	538		$	252
Average common shares outstanding - basic	242.6			242.6			242.6			242.6
Assumed settlement of performance share units	1.7			2.5			1.7			1.8
Average common shares outstanding - diluted	244.3			245.1			244.3			244.4
Earnings (loss) per common share – basic:
Continuing operations	$	1.21		$	1.26		$	2.23		$	1.92
Discontinued operations	—			(0.01		)	(0.01		)	(0.88		)
Earnings per common share – basic	$	1.21		$	1.25		$	2.22		$	1.04
Earnings (loss) per common share – diluted:
Continuing operations	$	1.20		$	1.25		$	2.21		$	1.91
Discontinued operations	—			(0.01		)	(0.01		)	(0.88		)
Earnings per common share – diluted	$	1.20		$	1.24		$	2.20		$	1.03

There were no potentially dilutive securities excluded from the diluted earnings per share calculations for the three and nine months ended September 30, 2014, and 2013.

Stock-based Compensation

Ameren’s long-term incentive plan available for eligible employees and directors, the 2006 Incentive Plan, was replaced prospectively for new grants by the 2014 Incentive Plan effective April 24, 2014. The 2014 Incentive 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 Incentive Plan. To the extent that the issuance of a share that is subject to an outstanding award under the 2006 Incentive Plan, as of April 24, 2014, would cause Ameren to exceed the maximum authorized shares under the 2006 Incentive Plan, the issuance of that share will take place under the 2014 Incentive Plan and will therefore reduce the maximum number of shares that may be granted under the 2014 Incentive Plan. The 2014 Incentive 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 September 30, 2014, and changes during the nine months ended September 30, 2014, under the 2006 Incentive Plan and the 2014 Incentive Plan are presented below:

	Performance Share Units
	Share Units		Weighted-average Fair Value Per Share Unit at Grant Date
Nonvested at January 1, 2014	1,218,544		$	33.23
Granted(a)	685,026		38.90
April Grants(b)	38,559		50.34
Forfeitures	(65,847	)	33.82
Vested(c)	(123,295	)	38.64
Nonvested at September 30, 2014	1,752,987		$	35.42

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

(b) In April 2014, certain executive officers were granted additional share units under the 2006 Incentive Plan and the 2014 Incentive Plan. The significant assumptions used to calculate fair value included a prorated three-year risk-free rate ranging from 0.76% to 0.79%, 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.

(c) 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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The fair value of each share unit awarded in 2014, excluding the April Grants, under the 2006 Incentive Plan and the 2014 Incentive 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. Ameren Missouri’s emission allowances are allocated by the EPA and therefore are recorded at zero cost. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

At September 30, 2014, Ameren’s and Ameren Missouri’s intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book values of both Ameren’s and Ameren Missouri’s renewable energy credits were $20 million and $22 million at September 30, 2014 and December 31, 2013, respectively.

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 and nine months ended September 30, 2014, and 2013:

		Three Months			Nine Months
	2014		2013		2014		2013
Ameren Missouri	$	1	$	—	$	7	$	(a)
Ameren Illinois		1		2		7		9
Ameren	$	2	$	2	$	14	$	9

(a) Less than $1 million.

Excise Taxes

Excise taxes levied on us are reflected on Ameren Missouri electric customer bills and on Ameren Missouri and Ameren Illinois natural gas customer bills. They are recorded gross in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” on

the statement of income or the statement of income and comprehensive income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the 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 and nine months ended September 30, 2014, and 2013:

	Three Months				Nine Months
	2014		2013		2014		2013
Ameren Missouri	$	47	$	49	$	120	$	120
Ameren Illinois	9		10		46		43
Ameren	$	56	$	59	$	166	$	163

Uncertain Tax Positions

With the adoption of new accounting guidance in the first quarter of 2014, unrecognized tax benefits are recorded as a reduction to the deferred tax assets for net operating losses and tax credit carryforwards within “Accumulated deferred income taxes, net” on our balance sheets. Unrecognized tax benefits that exceed these carryforwards are recorded in “Other deferred credits and liabilities” on our balance sheets. At September 30, 2014, unrecognized tax benefits of $89 million, $13 million, and $2 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 Ameren’s, Ameren Missouri’s and Ameren Illinois’ 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 total amount of reserves for unrecognized tax benefits (detriments) related to uncertain tax positions as of September 30, 2014, and December 31, 2013:

	September 30, 2014		December 31, 2013
Ameren	$	97	$	90
Ameren Missouri	35		31
Ameren Illinois	1		(1		)

The following table presents the amount of reserves for unrecognized tax benefits, included in the table above, related to uncertain tax positions that would impact results of operations, if recognized, as of September 30, 2014, and December 31, 2013:

	September 30, 2014		December 31, 2013
Ameren	$	55	$	54
Ameren Missouri	3		3
Ameren Illinois	—		—

In October 2014, a settlement was reached with the Appeals Office of the IRS for the years 2007 through 2010. During the

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fourth quarter of 2014, this settlement, which is primarily related to uncertain tax positions associated with the timing of research tax deductions, will result in a decrease in Ameren’s uncertain tax benefits of $16 million, of which $9 million is related to Ameren Missouri. This settlement will not have a material impact on Ameren’s or Ameren Missouri’s results of operations or liquidity.

Ameren’s federal income tax returns for the years 2011 and 2012 are before the Appeals Office of the IRS. 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 2011 and 2012. The potential settlement, which would primarily relate to uncertain tax positions associated with the timing of research tax deductions, is expected to result in a decrease in Ameren’s uncertain tax benefits of $6 million, all of which relates to Ameren Missouri and none of which will have a material impact on their respective results of operations or liquidity.

Ameren’s federal income tax return for the year 2013 is currently under examination by the IRS and it is reasonably possible that a settlement will be reached with the IRS examination team in the next 12 months for that year. The potential settlement, which would relate to the timing of research tax deductions and the tax basis of certain leases related to the divestiture of the merchant generation business, is expected to result in a decrease in Ameren’s uncertain tax benefits of $73 million, of which $17 million relates to Ameren Missouri and $1 million relates to Ameren Illinois. Although we are unable to estimate the impact of any potential settlement at this time, up to $55 million of the Ameren total could increase net income from

Ameren’s discontinued operations. Settlement of the remaining $18 million of uncertain tax positions at Ameren, as well as those positions at Ameren Missouri and Ameren Illinois, are associated with the timing of deductions and will not have a material impact on our results of operations.

In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of our unrecognized tax benefits to fluctuate. However, other than as described above, we do not believe any such fluctuations would be material to our 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. We 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 September 30, 2014, compared to December 31, 2013, to reflect the accretion of obligations to their fair value and an additional ARO at Ameren and Ameren Missouri of $2 million related to the retirement costs for a CCR storage facility, partially offset by immaterial settlements.

Noncontrolling Interests

As of September 30, 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 and nine months ended September 30, 2014, and 2013, are shown below:

	Three Months							Nine Months
	2014			2013				2014			2013
Noncontrolling interests, beginning of period	$	142		$	151		(a)	$	142		$	151		(a)
Net income from continuing operations attributable to noncontrolling interests	2			2				5			5
Dividends paid to noncontrolling interest holders	(2		)	(2		)		(5		)	(5		)
Noncontrolling interests, end of period	$	142		$	151		(a)	$	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,” respectively. 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 or issued authoritative accounting guidance relevant to the Ameren Companies.

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

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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' respective balance sheets. Beginning in the first quarter 2014, unrecognized tax benefits are recorded as a reduction to the deferred tax assets for net operating losses and tax credit carryforwards within “Accumulated deferred income taxes, net” on our 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.

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

In April 2014, FASB issued authoritative accounting guidance that changes the criteria for reporting and qualifying for discontinued operations. Under the new guidance, a component of an entity, or a group of components of an entity, that either meets the criteria to be classified as held for sale or is disposed of by sale or otherwise, is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results. The guidance includes expanded disclosure requirements for discontinued operations and additional disclosures about a disposal of an individually significant component of an entity that does not qualify for discontinued operations presentation. The guidance will be effective for the Ameren Companies in the first quarter of 2015 for components that are classified as held for sale or disposed of on or after January 1, 2015. Early adoption is permitted, but only for disposals or classifications as held for sale that have not been reported in financial statements previously issued. Therefore, Ameren’s existing discontinued operations would not be subject to the new disclosure requirements. The guidance will not affect the Ameren Companies’ results of operations, financial position, or liquidity, as this guidance is presentation-related only.

Revenue from Contracts with Customers

In May 2014, FASB issued authoritative accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP. The guidance requires an entity to recognize an amount of revenue for the transfer of promised goods or services to customers that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The guidance will be effective for the Ameren Companies in the first quarter of 2017. The Ameren Companies are currently assessing the impacts of this guidance.

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

Rate Shift Complaint and Earnings Complaint Cases

In February 2014, Noranda and 37 residential customers filed a rate shift complaint case and an earnings complaint case with the MoPSC.

On August 20, 2014, the MoPSC issued an order that rejected Noranda’s and the residential customers’ request in the rate shift complaint case. On September 12, 2014, Noranda, the MoOPC, the MIEC, and other parties filed a rehearing request, which was subsequently denied by 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 common equity authorized in the MoPSC's December 2012 electric rate order. The MoOPC, the MIEC, and other parties, participated in the earnings complaint case. On October 1, 2014, the MoPSC issued an order that rejected Noranda’s and the residential customers’ request in the earnings complaint case. On October 30, 2014, Noranda, the MoOPC, the MIEC, and other parties filed a rehearing request, which was subsequently denied by the MoPSC.

2014 Electric Rate Case

In July 2014, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $264 million. The rate request seeks recovery of increased net energy costs and rebates provided for customer-installed solar generation, as well as recovery of, and a return on, additional electric infrastructure investments made for the benefit of Ameren Missouri’s customers. Plant additions to rate base since the last electric rate order are expected to total approximately $1.4 billion through the true-up date in this rate case and include electric infrastructure investments for upgrades to the electrostatic precipitators at the coal-fired Labadie energy center, the replacement of the nuclear reactor vessel head at the Callaway energy center, two new substations in St. Louis, and the O’Fallon solar energy center, among other additions. Approximately $127 million of the request relates to an increase in net energy costs above the current levels included in base rates previously authorized by the MoPSC in its December 2012 electric rate order, 95% of which, absent initiation of this general rate proceeding, would have been reflected in rate adjustments implemented under Ameren Missouri’s existing FAC. The electric rate increase request is based on a 10.4% return on common equity, a capital structure composed of 51.6% common equity, an

17

electric rate base for Ameren Missouri of $7.3 billion, and a test year ended March 31, 2014, with certain pro-forma adjustments expected through the true-up date of December 31, 2014.

As a part of its filing, Ameren Missouri also requested continued use of the FAC and the regulatory tracking mechanisms for storm costs, vegetation management/ infrastructure inspection costs, pension and postretirement benefits, and uncertain income tax positions that the MoPSC previously authorized in earlier electric rate orders.

The MoPSC proceeding relating to the proposed electric service rate increase will take place over a period of up to 11 months and a decision by the MoPSC in such proceeding is expected by May 2015, with rates effective by June 2015. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, or whether any rate increase that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the increase goes into effect.

In October 2014, as part of this rate case proceeding, the MoOPC, the MIEC, and other parties, filed a rate shift request that seeks to reduce Noranda’s electric rates with an offsetting increase in electric rates for Ameren Missouri’s other customers. Ameren Missouri supplies electricity to Noranda’s aluminum smelter in southeast Missouri under a 15-year agreement, that is subject to termination as early as 2020 upon at least five years notice given by either party. Termination of the agreement by Ameren Missouri would require MoPSC approval.

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 accounting authority order that allowed Ameren Missouri to seek recovery of these fixed costs in an electric rate case. Ameren Missouri’s July 2014 electric rate case filing requested recovery of these fixed costs over five years. In February 2014, the MIEC and the MoOPC filed appeals of the MoPSC’s November 2013 accounting authority order with the Missouri Court of Appeals, Western District. Ameren Missouri has not recorded any potential revenue associated with this accounting authority 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 customer billings 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 September 30, 2014, Ameren Illinois had recorded regulatory assets of $76 million and $64 million, respectively, to reflect its expected 2014 and 2013 revenue requirement reconciliation adjustments, with interest. As of September 30, 2014, Ameren Illinois had recorded a regulatory liability of $13 million to reflect its 2012 revenue requirement reconciliation adjustment, with interest, which is being refunded to customers during 2014.

In December 2013, the ICC issued an order in Ameren Illinois' annual formula rate 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 rate treatment of accumulated deferred income taxes related to the transfer of former Ameren Missouri electric assets located 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, as revised in July 2014, will result in a $205 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. In August 2014, the ICC staff submitted its revised calculation of the revenue requirement. The ICC staff recommended a $205 million increase in Ameren Illinois’ electric delivery service revenue requirement. Other intervenors requested an electric delivery service revenue requirement up to $7 million lower than the revenue requirement recommended by the ICC staff. In October 2014, the administrative law judges issued a proposed order that reflected an increase to Ameren Illinois’ electric delivery service revenue requirement of $204 million. A final 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 common 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 common equity included in the ICC's order and also appealed the rate treatment of accumulated deferred income taxes related to the transfer of former Ameren Missouri natural gas assets located in Illinois to Ameren Illinois

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with the Appellate Court of the Fourth District of Illinois. Ameren Illinois sought a 10.4% return on common equity in this rate case.

ATXI Transmission Project

The Spoon River project in northwest Illinois is a MISO-approved transmission line project. In August 2014, ATXI made a filing with the ICC requesting a certificate of public convenience and necessity and project approval for the Spoon River project. A decision is expected from the ICC in 2015. A certificate of public convenience and necessity is required before ATXI can proceed with right-of-way acquisition.

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 with no material impact on net income. In March 2011, FERC issued an order authorizing the proposed rates to take effect, subject to refund when the final rates are determined. In November 2012, a FERC administrative law judge issued an initial decision finding that refunds were due to the wholesale customers. In September 2014, FERC issued an order affirming certain findings in the initial decision. Ameren and Ameren Illinois recognized in “Current regulatory liabilities” an estimate of $24 million and $13 million as of September 30, 2014, and December 31, 2013, respectively, for the refund due to the wholesale customers relating to billings since March 2011. In October 2014, Ameren Illinois refunded $24 million, including interest, to the wholesale customers and requested a rehearing on certain aspects of the order.

Ameren Illinois Electric Transmission Rate Refund

In July 2012, FERC issued an order concluding that Ameren Illinois improperly included acquisition premiums, including 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.

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 Illinois’ 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.

In June 2014, FERC issued an order that denied Ameren Illinois’ rehearing requests of the July 2012 order and the June 2013 order. Separately, in June 2014, FERC issued an order that established hearing and settlement procedures for Ameren Illinois’ July 2013 refund report. In July 2014, Ameren Illinois filed an appeal of FERC’s orders denying rehearing of the July 2012 and June 2013 orders with the United States Court of Appeals for the District of Columbia Circuit. Also in July 2014, Ameren Illinois separately filed a request for rehearing with FERC of its June 2014 order regarding the July 2013 refund report.

Ameren Illinois estimates the maximum pretax charge to earnings for this possible refund obligation through December 31, 2014, would be $19 million, before interest charges. For the nine months ended September 30, 2014, Ameren and Ameren Illinois recorded a $4 million reduction to “Operating Revenues - Electric” with a corresponding increase to “Current regulatory liabilities” for its estimate of the refund due to electric transmission customers based on the June 2014 order. If Ameren Illinois were to determine that a refund to its electric transmission customers in excess of the amount already recorded is probable, an additional charge to earnings would be recorded in the period in which that determination is made.

FERC Complaint Case

In November 2013, a customer group filed a complaint case with FERC seeking a reduction in the allowed base return on common equity for FERC-regulated MISO transmission rate base to 9.15%, as well as a limit on the common equity ratio, under the MISO tariff. Currently, the FERC-allowed base return on common equity for MISO transmission owners is 12.38%. In October 2014, FERC issued an order establishing settlement procedures and, if necessary, hearing procedures regarding the allowed base return on common equity and denied all other aspects of the MISO complaint case. This complaint case could result in a reduction to Ameren Illinois' and ATXI's allowed base return on common equity, which would result in a refund for transmission service revenues earned from the refund effective date of November 12, 2013.

In October 2014, FERC issued an order, which confirmed its June 2014 order, reducing the allowed base return on common equity for New England transmission owners from 11.14% to 10.57%, with rate incentives allowed up to 11.74%. The FERC orders in the New England transmission owners’ case applied observable market data from October 2012 to March 2013 to determine the allowed base return on common equity. FERC expects the evidence and the calculation used in the New England transmission owners’ case to guide its decision in the MISO complaint case. The calculation FERC will use to establish the allowed base return on common equity, which is based on a unique time period for each complaint case, will require multiple inputs based on observable market data specific to the utility industry and broader macroeconomic data. The unique time period of observable market data for the MISO complaint case has not been established by FERC. Due to the wide range of potential outcomes and significant uncertainty regarding the value of inputs required in FERC’s calculation, the Ameren

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Companies cannot reasonably estimate the impact, if any, that a resolution in the MISO complaint case could have on their allowed base return on common equity.

On November 6, 2014, we filed a request with FERC to include an incentive adder of up to 50 basis points for participation in an RTO on the allowed base return on common equity. The filing requests a November 7, 2014 effective date and seeks authorization to defer collection of the incentive adder until after the issuance of the final order addressing the pending MISO complaint case discussed above. FERC is required to issue an order within 60 days of our filing.

If MISO’s allowed base return on common equity was lowered to 10.57%, as established in the New England transmission owners’ case, with no additional rate incentives, the required refund for Ameren and Ameren Illinois would be $14 million and $11 million, respectively, from the refund effective date of November 12, 2013 through September 30, 2014. The estimated annual reduction in revenues if the MISO return on common equity was 10.57% for Ameren and Ameren Illinois would be $16 million and $12 million, respectively. Ameren Missouri would not expect that a reduction in the FERC-allowed base return on common equity for MISO transmission owners would be material to its results of operations, financial position or liquidity. If Ameren and Ameren Illinois were to determine that a refund to their electric transmission customers could be reasonably estimated, a charge to earnings would be recorded for the refund in the period in which that determination is made.

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 May 2012 order 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. 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 an expense is not probable, and therefore no liability has been recorded as of September 30, 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 $120 million. As of September 30, 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 that 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, drawings under committed credit agreements, commercial paper issuances, or, in the case of Ameren Missouri and Ameren Illinois, short-term intercompany borrowings.

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 nine months ended September 30, 2014, but they were used to support commercial paper issuances and to issue letters of credit. 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 September 30, 2014, was $1.3 billion.

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Commercial Paper

The following table presents commercial paper outstanding at Ameren (parent), Ameren Missouri and Ameren Illinois as of September 30, 2014, and December 31, 2013. Ameren Illinois established a commercial paper program in May 2014.

	September 30, 2014		December 31, 2013
Ameren (parent)	$	499	$	368
Ameren Missouri	65		—
Ameren Illinois	189		—
Ameren Consolidated	$	753	$	368

The following table summarizes the commercial paper activity and relevant interest rates under Ameren’s (parent), Ameren Missouri’s and Ameren Illinois’ commercial paper programs for the nine months ended September 30, 2014, and 2013:

	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated
2014
Average daily commercial paper outstanding	$	386		$	141		$	157		$	609
Weighted-average interest rate	0.36		%	0.38		%	0.31		%	0.35		%
Peak commercial paper during period(a)	$	531		$	495		$	300		$	907
Peak interest rate	0.75		%	0.70		%	0.34		%	0.75		%
2013
Average daily commercial paper outstanding	$	26		$	—		$	—		$	26
Weighted-average interest rate	0.52		%	—		%	—		%	0.52		%
Peak commercial paper during period(a)	$	92		$	—		$	—		$	92
Peak interest rate	0.85		%	—		%	—		%	0.85		%

(a) The timing of peak commercial paper issuances varies by company, and therefore the peak 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 is 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 September 30, 2014, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2012 Credit Agreements, were 49%, 48% and 46%, 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 September 30, 2014, was 6.1 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 September 30, 2014.

Money Pools

Ameren (parent) 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 (parent) may participate in the utility money pool only as a lender. Surplus internal funds are contributed to the utility money pool from participants. The primary sources of external funds for the utility money pool are the 2012 Credit Agreements and the commercial paper programs. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by

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regulatory authorizations. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the three and nine months ended September 30, 2014, was 0.10% and 0.23%, respectively (2013 -

0.05% and 0.08%, respectively).

See Note 8 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three and nine months ended September 30, 2014, and 2013.

NOTE 4 - LONG-TERM DEBT

Ameren (parent)

In May 2014, Ameren (parent) repaid at maturity $425 million of its 8.875% senior unsecured notes due May 15, 2014, plus accrued interest. The notes were repaid with proceeds from commercial paper issuances.

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 proceeds of $348 million, which were used to repay at maturity $104 million of its 5.50% senior secured notes due May 15, 2014 and to repay a portion of its short-term debt.

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
5.95% 1993 Series C-1 due 2026	35
5.70% 1993 Series C-2 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.

In June 2014, Ameren Illinois issued $250 million of 4.30% senior secured notes due July 1, 2044, with interest payable semiannually on January 1 and July 1 of each year, beginning January 1, 2015. Ameren Illinois received proceeds of $246 million, which were used to repay a portion of its short-term debt.

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 September 30, 2014, at an assumed annual interest rate of 5% and dividend rate of 6%.

	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	4.6	$	3,304		≥2.5	126.3	$	2,823
Ameren Illinois	≥2.0	6.7		3,636	(d)	≥1.5	2.4		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 $833 million and $204 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.

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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% equity capital structure. As of September 30, 2014, Ameren Illinois had a 54% equity capital structure.

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 September 30, 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 for the three and nine months ended September 30, 2014, and 2013:

	Three Months				Nine Months
	2014		2013		2014		2013
Ameren:(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	10	$	10	$	26	$	26
Interest income on industrial development revenue bonds	6		7		20		21
Interest income	3		2		8		3
Other	2		1		6		1
Total miscellaneous income	$	21	$	20	$	60	$	51
Miscellaneous expense:
Donations	$	3	$	2	$	9	$	7
Other	4		3		11		11
Total miscellaneous expense	$	7	$	5	$	20	$	18
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	9	$	8	$	24	$	22
Interest income on industrial development revenue bonds	6		7		20		21
Interest income	—		1		1		1
Total miscellaneous income	$	15	$	16	$	45	$	44
Miscellaneous expense:
Donations	$	2	$	—	$	5	$	3
Other	2		2		5		7
Total miscellaneous expense	$	4	$	2	$	10	$	10
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	1	$	2	$	2	$	4
Interest income	2		1		5		2
Other	1		1		5		1
Total miscellaneous income	$	4	$	4	$	12	$	7
Miscellaneous expense:
Donations	$	—	$	—	$	3	$	3
Other	2		3		4		4
Total miscellaneous expense	$	2	$	3	$	7	$	7

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

NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives 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 September 30, 2014, and December 31, 2013. As of September 30, 2014, these contracts ran through October 2017, 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)	52	(b)	52	66	(b)	66
Natural gas (in mmbtu)	23	102	125	28	108	136
Power (in megawatthours)	1	11	12	3	11	14
Uranium (pounds in thousands)	557	(b)	557	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. We 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 September 30, 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 commodity contracts, none of which were designated as hedging instruments, as of September 30, 2014, and December 31, 2013:

	Balance Sheet Location	Ameren  Missouri		Ameren  Illinois		Ameren
2014
Fuel oils	Other current assets	$	3	$	—	$	3
Natural gas	Other current assets	—		1		1
	Other assets	—		1		1
Power	Other current assets	10		—		10
	Other assets	1		—		1
	Total assets	$	14	$	2	$	16
Fuel oils	Other current liabilities	$	5	$	—	$	5
	Other deferred credits and liabilities	1		—		1
Natural gas	Other current liabilities	3		16		19
	Other deferred credits and liabilities	3		6		9
Power	Other current liabilities	6		8		14
	Other deferred credits and liabilities	—		116		116
Uranium	Other current liabilities	2		—		2
	Other deferred credits and liabilities	1		—		1
	Total liabilities	$	21	$	146	$	167
2013
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
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

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 September 30, 2014, and December 31, 2013:

	Ameren Missouri			Ameren Illinois			Ameren
2014
Fuel oils derivative contracts(a)	$	(5	)	$	—		$	(5	)
Natural gas derivative contracts(b)	(6		)	(20		)	(26		)
Power derivative contracts(c)	5			(124		)	(119		)
Uranium derivative contracts(d)	(3		)	—			(3		)
2013
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 losses associated with fuel oil derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through December 2017. Current losses deferred as regulatory assets include $4 million and $4 million at Ameren and Ameren Missouri, respectively.

(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 2018 at Ameren Illinois. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively. Current losses deferred as regulatory assets include $19 million, $3 million, and $16 million at Ameren, Ameren Missouri and Ameren Illinois, respectively.

(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. Current gains deferred as regulatory liabilities include $10 million and $10 million at Ameren and Ameren Missouri. Current losses deferred as regulatory assets include $14 million, $6 million, and $8 million at Ameren, Ameren Missouri and Ameren Illinois, respectively.

(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. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri, respectively.

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

We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) 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.

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 September 30, 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	$	14	$	7	$	—	$	7
Ameren Illinois	2		1		—		1
Ameren	$	16	$	8	$	—	$	8
Liabilities:
Ameren Missouri	$	21	$	7	$	5	$	9
Ameren Illinois	146		1		—		145
Ameren	$	167	$	8	$	5	$	154
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 September 30, 2014, if counterparty groups were to fail completely to perform on contracts, Ameren, Ameren Missouri and Ameren Illinois' maximum exposure was $6 million, $4 million, and $2 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 September 30, 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 $4 million, $3 million, and $1 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, Ameren Missouri and Ameren Illinois was $6 million, $6 million, and $- million, respectively.

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Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of September 30, 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 September 30, 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	$	62	$	2	$	57
Ameren Illinois	61		—		56
Ameren	$	123	$	2	$	113
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 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

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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 September 30, 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	$	3	$	(3	)	Option model	Volatilities(%)(b)	2 - 27	14
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.25 - 1	0.72
								Ameren Missouri credit risk(%)(c)(d)	0.43	(e)
	Natural gas	1		—			Discounted cash flow	Nodal basis($/mmbtu)(c)	(0.10) - 0	(0.10)
								Counterparty credit risk(%)(c)(d)	0.30 - 2	0.62
								Ameren Illinois credit risk(%)(c)(d)	0.43	(e)
	Power(f)	10		(129		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	29 - 59	35
								Estimated auction price for FTRs($/MW)(b)	(1,853) - 2,087	199
								Nodal basis($/MWh)(c)	(6) - 0	(3)
								Counterparty credit risk(%)(c)(d)	0.40	(e)
								Ameren Missouri and Ameren Illinois credit risk(%)(c)(d)	0.43	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 5	5
								Escalation rate(%)(b)(g)	2	(e)
							Contract price allocation	Estimated renewable energy credit costs($/credit)(b)	5 - 7	6
	Uranium	—		(3		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	35 - 41	36
Ameren Missouri	Fuel oils	$	3	$	(3	)	Option model	Volatilities(%)(b)	2 - 27	14
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.25 - 1	0.72
								Ameren Missouri credit risk(%)(c)(d)	0.43	(e)
	Power(f)	10		(5		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)	30 - 59	48
								Estimated auction price for FTRs($/MW)(b)	(1,853) - 2,087	199
								Counterparty credit risk(%)(c)(d)	0.40	(e)
								Ameren Missouri credit risk(%)(c)(d)	0.43	(e)
	Uranium	—		(3		)	Discounted cash flow	Average forward uranium pricing($/pound)(b)	35 - 41	36
Ameren Illinois	Natural gas	$	1	$	—		Discounted cash flow	Nodal basis($/mmbtu)(c)	(0.10) - 0	(0.10)
								Counterparty credit risk(%)(c)(d)	0.30 - 2	0.62
								Ameren Illinois credit risk(%)(c)(d)	0.43	(e)
	Power(f)	—		(124		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b)	29 - 42	33
								Nodal basis($/MWh)(b)	(6) - 0	(3)
								Ameren Illinois credit risk(%)(c)(d)	0.43	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)(b)	4 - 5	5
								Escalation rate(%)(b)(g)	2	(e)
							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.

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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 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 nine months of 2014 or 2013. At September 30, 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.

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The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of September 30, 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	$	—	$	—	$	3	$	3
	Natural gas	—		1		1		2
	Power	—		1		10		11
	Total derivative assets - commodity contracts	$	—	$	2	$	14	$	16
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	348		—		—		348
	Debt securities:
	Corporate bonds	—		60		—		60
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		100		—		100
	Asset-backed securities	—		11		—		11
	Other	—		5		—		5
	Total nuclear decommissioning trust fund	$	349	$	178	$	—	$	527	(b)
	Total Ameren	$	349	$	180	$	14	$	543
Ameren	Derivative assets - commodity contracts(a):
Missouri	Fuel oils	$	—	$	—	$	3	$	3
	Power	—		1		10		11
	Total derivative assets - commodity contracts	$	—	$	1	$	13	$	14
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	348		—		—		348
	Debt securities:
	Corporate bonds	—		60		—		60
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		100		—		100
	Asset-backed securities	—		11		—		11
	Other	—		5		—		5
	Total nuclear decommissioning trust fund	$	349	$	178	$	—	$	527	(b)
	Total Ameren Missouri	$	349	$	179	$	13	$	541
Ameren	Derivative assets - commodity contracts(a):
Illinois	Natural gas	$	—	$	1	$	1	$	2
Liabilities:
Ameren	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	3	$	—	$	3	$	6
	Natural gas	2		26		—		28
	Power	—		1		129		130
	Uranium	—		—		3		3
	Total Ameren	$	5	$	27	$	135	$	167
Ameren	Derivative liabilities - commodity contracts(a):
Missouri	Fuel oils	$	3	$	—	$	3	$	6
	Natural gas	2		4		—		6
	Power	—		1		5		6
	Uranium	—		—		3		3
	Total Ameren Missouri	$	5	$	5	$	11	$	21
Ameren	Derivative liabilities - commodity contracts(a):
Illinois	Natural gas	$	—	$	22	$	—	$	22
	Power	—		—		124		124
	Total Ameren Illinois	$	—	$	22	$	124	$	146

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

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

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The following table 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.

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The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended September 30, 2014:

		Net derivative commodity contracts
Three Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at July 1, 2014	$	2		$	(a)		$	2
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(2	)		(a)			(2	)
Ending balance at September 30, 2014	$	—		$	(a)		$	—
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	(2	)	$	(a)		$	(2	)
Natural gas:
Beginning balance at July 1, 2014	$	—		$	—		$	—
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			1			1
Ending balance at September 30, 2014	$	—		$	1		$	1
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	—		$	—		$	—
Power:
Beginning balance at July 1, 2014	$	15		$	(103	)	$	(88	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(5	)		(23	)		(28	)
Settlements		(5	)		2			(3	)
Ending balance at September 30, 2014	$	5		$	(124	)	$	(119	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	(6	)	$	(22	)	$	(28	)
Uranium:
Beginning balance at July 1, 2014	$	(7	)	$	(a)		$	(7	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		3			(a)			3
Settlements		1			(a)			1
Ending balance at September 30, 2014	$	(3	)	$	(a)		$	(3	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	3		$	(a)		$	3

(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 September 30, 2013:

		Net derivative commodity contracts
Three Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at July 1, 2013	$	3		$	(a)		$	3
Realized and unrealized gains (losses) included in regulatory assets/liabilities		1			(a)			1
Purchases		1			(a)			1
Sales		(1	)		(a)			(1	)
Settlements		(1	)		(a)			(1	)
Ending balance at September 30, 2013	$	3		$	(a)		$	3
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	1		$	(a)		$	1
Natural gas:
Beginning balance at July 1, 2013	$	(1	)	$	2		$	1
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			(2	)		(2	)
Purchases		1			—			1
Ending balance at September 30, 2013	$	—		$	—		$	—
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	—		$	(1	)	$	(1	)
Power:
Beginning balance at July 1, 2013	$	37		$	(80	)	$	(43	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(3	)		(17	)		(20	)
Sales		1			—			1
Settlements		(6	)		3			(3	)
Transfers into Level 3		(1	)		—			(1	)
Ending balance at September 30, 2013	$	28		$	(94	)	$	(66	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	(2	)	$	(16	)	$	(18	)
Uranium:
Beginning balance at July 1, 2013	$	(3	)	$	(a)		$	(3	)
Purchases		(2	)		(a)			(2	)
Ending balance at September 30, 2013	$	(5	)	$	(a)		$	(5	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	(2	)	$	(a)		$	(2	)

(a) Not applicable.

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The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2014:

		Net derivative commodity contracts
Nine 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		(3	)		(a)			(3	)
Settlements		(2	)		(a)			(2	)
Ending balance at September 30, 2014	$	—		$	(a)		$	—
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	(2	)	$	(a)		$	(2	)
Natural gas:
Beginning balance at January 1, 2014	$	—		$	—		$	—
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			1			1
Purchases		—			(1	)		(1	)
Settlements		—			1			1
Ending balance at September 30, 2014	$	—		$	1		$	1
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	—		$	—		$	—
Power:
Beginning balance at January 1, 2014	$	19		$	(108	)	$	(89	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(23	)		(19	)		(42	)
Purchases		34			—			34
Settlements		(25	)		3			(22	)
Ending balance at September 30, 2014	$	5		$	(124	)	$	(119	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	(3	)	$	(21	)	$	(24	)
Uranium:
Beginning balance at January 1, 2014	$	(6	)	$	(a)		$	(6	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(1	)		(a)			(1	)
Settlements		4			(a)			4
Ending balance at September 30, 2014	$	(3	)	$	(a)		$	(3	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	—		$	(a)		$	—

(a) Not applicable.

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The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2013:

		Net derivative commodity contracts
Nine Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2013	$	5		$	(a)		$	5
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(1	)		(a)			(1	)
Purchases		2			(a)			2
Sales		(1	)		(a)			(1	)
Settlements		(2	)		(a)			(2	)
Ending balance at September 30, 2013	$	3		$	(a)		$	3
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 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 September 30, 2013	$	—		$	—		$	—
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	—		$	—		$	—
Power:
Beginning balance at January 1, 2013	$	11		$	(111	)	$	(100	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		3			(2	)		1
Purchases		40			—			40
Sales		1			—			1
Settlements		(28	)		19			(9	)
Transfers into Level 3		(3	)		—			(3	)
Transfers out of Level 3		4			—			4
Ending balance at September 30, 2013	$	28		$	(94	)	$	(66	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	—		$	(7	)	$	(7	)
Uranium:
Beginning balance at January 1, 2013	$	(2	)	$	(a)		$	(2	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(2	)		(a)			(2	)
Purchases		(2	)		(a)			(2	)
Settlements		1			(a)			1
Ending balance at September 30, 2013	$	(5	)	$	(a)		$	(5	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	(2	)	$	(a)		$	(2	)

(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 and nine months ended September 30, 2014, and 2013, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. For the three and nine months ended September 30, 2014 there were no transfers between Level 2 and Level 3 related to derivative commodity contracts. For the three months ended September 30, 2013 there were $(1) million of transfers out of Level 2 into Level 3 related to power contracts at Ameren and Ameren Missouri. For the nine months ended September 30, 2013 there were $(3) million of transfers out of Level 2 into Level 3 and $4 million of transfers into Level 2 out of Level 3 related to power contracts at Ameren and Ameren Missouri.

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

36

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 September 30, 2014, and December 31, 2013:

	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:(a)
Long-term debt and capital lease obligations (including current portion)	$	5,944	$	6,647	$	6,038	$	6,584
Preferred stock	142		122		142		118
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	4,004	$	4,466	$	3,757	$	4,124
Preferred stock	80		73		80		71
Ameren Illinois:
Long-term debt	$	1,940	$	2,181	$	1,856	$	2,028
Preferred stock	62		49		62		47

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

NOTE 8 - RELATED PARTY TRANSACTIONS

Ameren (parent) 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 respective 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 and the money pool arrangements discussed in Note 3 - Short-term Debt and Liquidity of this report.

Electric Power Supply Agreements

In 2014, Ameren Illinois used an RFP process, administered by the IPA, to procure energy products that will settle physically from December 1, 2014, through May 31, 2017. Ameren Missouri was among the winning suppliers in the energy product RFP process. As a result, in 2014, Ameren Missouri and Ameren Illinois entered into energy product agreements by which Ameren Missouri agreed to sell and Ameren Illinois agreed to purchase 168,400 megawatthours at an average price of $51 per megawatthour during the period of January 1, 2015, through February 28, 2017.

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three and nine months ended September 30, 2014, and 2013.

				Three Months				Nine Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2014	$	2	$	(a)	$	5	$	(a)
agreements with Ameren Illinois		2013		(b)		(a)		1		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2014		6		(b)		15		1
rent and facility services		2013		4		(b)		16		1
Ameren Missouri and Ameren Illinois	Operating Revenues	2014		(b)		(b)		1		(b)
miscellaneous support services		2013		1		(b)		1		2
Total Operating Revenues		2014	$	8	$	(b)	$	21	$	1
		2013		5		(b)		18		3
Ameren Illinois power supply	Purchased Power	2014	$	(a)	$	2	$	(a)	$	5
agreements with Ameren Missouri		2013		(a)		(b)		(a)		1
Ameren Illinois transmission	Purchased Power	2014		(a)		1		(a)		2
services with ATXI		2013		(a)		1		(a)		2
Total Purchased Power		2014	$	(a)	$	3	$	(a)	$	7
		2013		(a)		1		(a)		3

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				Three Months				Nine Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Ameren Services support services	Other Operations and Maintenance	2014	$	25	$	26	$	90	$	80
agreement		2013		25		22		85		70
Insurance premiums(c)	Other Operations and Maintenance	2014		(b)		(a)		(b)		(a)
		2013		(b)		(a)		(b)		(a)
Total Other Operations and		2014	$	25	$	26	$	90	$	80
Maintenance Expenses		2013		25		22		85		70
Money pool borrowings (advances)	Interest Charges	2014	$	(b)	$	(b)	$	(b)	$	(b)
		2013		(b)		(b)		(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.

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 September 30, 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.

(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. 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. The coverage commences after the first 52 weeks of insurance coverage from NEIL concludes and is a weekly indemnity of up to $0.9 million 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.

38

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 on nuclear facilities are covered under NEIL’s policies, subject to an industrywide aggregate policy limit of $3.24 billion, or $1.83 billion, for events not involving radiation contamination within a 12-month period for coverage for such terrorist acts.

If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our energy centers, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We also have entered into various long-term commitments for purchased power and natural gas for distribution. The table below presents our estimated fuel, purchased power, and other commitments at September 30, 2014. Ameren’s and Ameren Missouri’s purchased power commitments include a 102-megawatt power purchase agreement with a wind farm operator, which expires in 2024. Ameren’s and Ameren Illinois’ purchased power commitments include the Ameren Illinois power purchase agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services at September 30, 2014. In addition, the Other column includes Ameren's and Ameren Missouri's obligations related to customer energy efficiency programs under the MEEIA as approved by the MoPSC's December 2012 electric rate order. Ameren Missouri expects to incur costs of $17 million during the remainder of 2014 and $64 million in 2015 for these customer energy efficiency programs.

	Coal		Natural Gas(a)		Nuclear Fuel		Purchased Power(b)		Methane Gas		Other		Total
Ameren:(c)
2014	$	151	$	93	$	62	$	62	$	1	$	88	$	457
2015	635		225		56		190		3		156		1,265
2016	659		127		69		105		4		76		1,040
2017	682		80		59		66		4		50		941
2018	111		41		61		55		5		51		324
Thereafter	114		101		179		645		91		350		1,480
Total	$	2,352	$	667	$	486	$	1,123	$	108	$	771	$	5,507
Ameren Missouri:
2014	$	151	$	16	$	62	$	4	$	1	$	60	$	294
2015	635		39		56		21		3		110		864
2016	659		21		69		21		4		39		813
2017	682		13		59		21		4		26		805
2018	111		8		61		21		5		27		233
Thereafter	114		29		179		120		91		183		716
Total	$	2,352	$	126	$	486	$	208	$	108	$	445	$	3,725
Ameren Illinois:
2014	$	—	$	77	$	—	$	58	$	—	$	9	$	144
2015	—		186		—		169		—		28		383
2016	—		106		—		84		—		24		214
2017	—		67		—		45		—		24		136
2018	—		33		—		34		—		24		91
Thereafter	—		72		—		525		—		167		764
Total	$	—	$	541	$	—	$	915	$	—	$	276	$	1,732

(a) Includes amounts for generation and for distribution.

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

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

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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 and implementing environmental regulations that will have a significant impact on the electric utility industry. Over time, compliance with these regulations could be 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 existing energy centers through the proposed Clean Power Plan and from new energy centers through the NSPS; 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 Ameren Missouri’s energy centers. These new and proposed regulations, if adopted, are likely to be challenged through litigation, so their ultimate implementation, as well as the timing of any such implementation, is uncertain. Although many details of the future regulations are unknown, the combined effects of the new and proposed environmental regulations could result in significant capital expenditures and increased operating costs for Ameren and Ameren Missouri. Compliance with these environmental laws and regulations could be prohibitively expensive, result in the closure or alteration of the operation of some of Ameren Missouri’s energy centers, or require capital investment. Ameren and Ameren Missouri expect these costs would be recoverable through rates, subject to MoPSC prudence review, but the nature and timing of costs, as well as the applicable regulatory framework, could result in regulatory lag.

As of September 30, 2014, Ameren and Ameren Missouri estimate capital expenditure investments of $325 million to $375 million through 2018 to comply with existing environmental regulations. This estimate assumes that CCR will continue to be regulated as nonhazardous. Considerable uncertainty remains in this estimate. The actual amount of capital investments required

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. This estimate does not include the impacts of the proposed Clean Power Plan’s reduction in emissions of CO₂, which is discussed below.

Ameren Missouri's current plan for compliance with existing environmental regulations 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. Ameren Missouri's compliance plan assumes electrostatic precipitator upgrades at the Labadie energy center and the installation of additional controls including mercury control technology at multiple energy centers within its coal-fired fleet through 2018. However, Ameren Missouri is 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. As the Clean Power Plan is still subject to revision by the EPA and implementation by the states, Ameren Missouri has not finalized a compliance plan for the proposed rule.

The following sections describe the more significant new or proposed environmental laws and rules and environmental enforcement and remediation matters 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 regulations 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 and upheld the CSAPR. In October 2014, the United States Court of Appeals for the District of Columbia Circuit granted the EPA’s motion to lift the stay on CSPAR. The CSPAR will become effective on January 1, 2015, for SO₂ and annual NO_x reductions, and on May 1, 2015, for ozone season NO_x reductions, with further reductions in 2017 and in subsequent years. The EPA did not revise the emission reductions previously included in 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. Ameren Missouri does not expect to make additional capital investments to comply with the CSAPR. However, Ameren Missouri will incur additional operations and

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maintenance costs to lower its emissions at one or more of its energy centers for compliance with the CSAPR. These higher operations and maintenance costs are expected to 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, trace 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, compliance can be achieved by averaging emissions from similar 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 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 reviewing the United States Court of Appeals for the District of Columbia Circuit’s decision in October 2014 lifting the stay on the CSAPR. As discussed above, the CSAPR allowance programs will begin in 2015. Ameren Missouri expects to have sufficient allowances for 2015 to avoid making external purchases to comply with CSAPR.

Greenhouse Gas Regulation

Beginning in 2011, greenhouse gas emissions from stationary sources, such as power plants, became subject to regulation under the Clean Air Act. As a result of this action, Ameren Missouri is 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 2011 for regulating greenhouse gas emissions from stationary sources, such as power plants, through operating permits and the NSR Programs. The rule requires any source that already has an operating permit to have provisions relating to greenhouse gas emissions added to its permit upon renewal. Currently, all Ameren Missouri energy centers have operating permits that have been modified to address greenhouse gas emissions. In June 2014, the United States Supreme Court ruled that the EPA may regulate greenhouse gas emissions through operating permit processes and NSR programs at stationary sources that are already subject to those programs, but may not apply operating permit processes and NSR programs to non-stationary sources solely as a result of their greenhouse gas emissions. Ameren Missouri is currently evaluating the decision and the impact, if any, on its operations.

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 power plants. The proposed standards would establish separate emissions limits for new natural gas-fired plants and new coal-fired plants. In June 2014, the EPA proposed the Clean Power Plan, which sets forth CO₂ emissions standards that would be applicable to existing power plants. The proposed Clean Power Plan would require each state to develop plans to achieve CO₂ emission rates that the EPA calculated for each state. The EPA believes, based on their assumptions, that the Clean Power Plan would achieve a 30% decrease in CO₂ emissions from 2005 levels by 2030. The proposed rule also has interim goals of aggressively reducing CO₂ emissions by 2020. The EPA expects the proposed rule will be finalized by June 2015. After the proposed rule is finalized, states will have from one to three years to develop compliance plans. States will be allowed to develop independent plans or join with other states to develop joint plans. Ameren Missouri is evaluating the proposed Clean Power Plan and the potential impact to its operations. Significant uncertainty exists regarding the standard for existing power plants as the finalized rule could be different from the proposed rule and will be subject to legal challenges, both of which may result in the amount and timing of CO₂ emission reductions being revised.

Based on preliminary studies, if the proposed Clean Power Plan was to be made final, Ameren Missouri anticipates new or accelerated capital expenditures and increased fuel costs would be required to achieve compliance. As proposed, the Clean Power Plan would require the states, including Missouri and Illinois, to submit compliance plans as early as 2016. The states’ compliance plans may require Ameren Missouri to construct combined cycle gas-fired and renewable energy centers, currently estimated to cost approximately $2 billion by 2020, that Ameren Missouri believes would otherwise not be necessary to meet the energy needs of its customers. Additionally, Missouri’s implementation of the proposed rules, if adopted, could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and gas-fired energy centers. Ameren Missouri expects all of these increased costs, which could begin in 2017, would be recoverable, subject to MoPSC prudence review, through substantially higher electric rates charged to its customers.

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 Ameren Missouri’s energy centers, 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 its 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

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investment to comply with greenhouse gas limitations to the extent the investments are reflected and recovered timely in rates charged to customers.

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. 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 August 2014, the EPA published the final rule applicable to cooling water intake structures at existing power plants. The rule requires a case-by-case evaluation and plan for reducing the mortality of aquatic organisms impinged on the facility’s intake screens or entrained through the plant's cooling water system.Implementation of this rule will be administered through each power plant’s water discharge permitting process. All coal-fired and nuclear energy centers at Ameren Missouri are subject to this rule. The rule could have an adverse effect on Ameren’s and Ameren Missouri’s 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 electric rates charged to our customers.

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. The EPA is expected 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 for CCR at Ameren Missouri’s coal-fired 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 CCR without classifying it as waste. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric power plants would apply to ash ponds and CCR management and that it intended to align the effluent limitations 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 evaluating the proposed regulations to determine whether the current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. Ameren Missouri is evaluating the potential compliance costs associated 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 laws 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 September 30, 2014, Ameren Missouri had completed remediation at the last remaining former MGP site for which remediation was required. Ameren Missouri does not have a rate rider mechanism that permits it to recover from utility customers remediation costs associated with former MGP sites.

As of September 30, 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 remediation cost rate riders. To be recoverable, such costs must be prudently incurred and are subject to annual review by the ICC. As of September 30, 2014, Ameren Illinois estimated the obligation related to these former MGP sites at $254 million to $316 million. Ameren and Ameren Illinois recorded a liability of $254 million to represent their estimated minimum obligation for these sites, as no other amount within the range was a better estimate.

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The scope and extent to which these former MGP sites are remediated may fluctuate as investigation and 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 September 30, 2014, Ameren Illinois estimated the obligation related to the landfill 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 September 30, 2014, Ameren Illinois recorded a liability of $0.7 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 September 30, 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. At the other federal agency-mandated cleanup site, Ameren Missouri was a customer of an electrical equipment repair and disposal company that previously operated a facility in Cape Girardeau, Missouri. 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, believes it has no liability at September 30, 2014, for this site.

Ameren Missouri also participated in the investigation of various sites located in Sauget, Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies, including Solutia, Inc. that former landfills and lagoons 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 September 30, 2014, Ameren Missouri estimated its obligation related to Sauget Area 2 at $1 million to $2.5 million. Ameren Missouri recorded a liability of $1 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate.

In December 2012, Ameren Missouri signed an administrative order with the EPA and agreed to investigate soil and groundwater conditions at an Ameren Missouri-owned substation in St. Charles, Missouri. As of September 30, 2014, Ameren Missouri estimated the obligation related to the cleanup at $2.2 million to $4.5 million. Ameren Missouri recorded a liability of $2.2 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.

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, Ameren Missouri claims that the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In September 2014, the United States District Court for the Eastern District of Missouri ordered the case to be transferred to the United States District Court for the Southern District of New York for trial. The transfer order has been stayed pending resolution of Ameren Missouri’s request for appellate review of that order by the United States Court of Appeals for the Eight Circuit.

In June 2014, Ameren Missouri reached a settlement with another group of insurers who provided Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In accordance with the terms of that settlement, Ameren Missouri received a payment of $27 million. As of September 30, 2014, Ameren Missouri had an insurance receivable balance of $41 million and expects to ultimately collect this receivable from the remaining insurance company in the pending litigation described above. This receivable is included in “Other assets” on Ameren’s

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and Ameren Missouri’s balance sheets as of September 30, 2014.

Ameren's and Ameren Missouri's results of operations, financial position and liquidity could be adversely affected if Ameren Missouri's remaining liability insurance claim is not paid.

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 81 as of September 30, 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 September 30, 2014:

Ameren	Ameren Missouri	Ameren Illinois	Total(a)
1	48	62	75

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

As of September 30, 2014, Ameren, Ameren Missouri and Ameren Illinois had liabilities of $13 million, $5 million, and $8 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 September 30, 2014, the trust fund balance was $22 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. Also, in late 2012, five other cities issued tax liability notices alleging that Ameren Illinois failed to collect an immaterial amount of taxes from certain accounts. Ameren Illinois believes its defenses to the allegations are meritorious. As of September 30, 2014, Ameren Illinois estimated its obligation at $2 million to $5 million. Ameren Illinois recorded a liability of $2 million, which reflects potential settlements with the Illinois cities.

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 paid 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 has historically collected one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway energy center. However, as described below, Ameren Missouri has suspended collection of this fee.

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 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

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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. In November 2013, the court 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, which became effective on May 16, 2014. Since the nuclear waste fee was previously included in Ameren Missouri’s FAC, 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. The lawsuit 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. The parties entered into a settlement agreement that provides for annual recovery of additional spent fuel storage and related costs incurred from 2010 through 2016, with the ability to extend the recovery period as mutually agreed to by the parties. 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 fourth quarter of 2014. This reimbursement is included in "Miscellaneous accounts and notes receivable" on Ameren’s and Ameren Missouri’s September 30, 2014 and December 31, 2013 respective 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. Ameren Missouri will continue to 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 a generic environmental impact statement and a final rule to address the court's ruling. In September 2014, the NRC published its final rule and generic environmental impact statement. On October 20, 2014, the final rule became effective and the NRC lifted its suspension on final licensing decisions.

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. Annual decommissioning costs of $7 million are included in the costs of service used to establish electric rates for Ameren Missouri's customers. 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 was filed with the MoPSC in September 2011. The MoPSC has authorized a delay of the 2014 cost study and funding analysis filing until 2015 pending the outcome of Ameren Missouri’s operating license extension application under review by the NRC. 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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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 September 30, 2014, the plan’s estimated investment performance through September 30, 2014, and Ameren’s pension funding policy, Ameren expects to make annual contributions of $40 million to $110 million in each of the next five years, with aggregate estimated contributions of $340 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 (benefit) for Ameren’s pension and postretirement benefit plans for the three and nine months ended September 30, 2014, and 2013:

	Pension Benefits												Postretirement Benefits
	Three Months						Nine Months						Three Months						Nine Months
	2014			2013			2014			2013			2014			2013			2014			2013
Service cost	$	20		$	23		$	60		$	69		$	5		$	6		$	14		$	17
Interest cost	46			40			137			121			12			11			37			34
Expected return on plan assets	(58		)	(54		)	(172		)	(162		)	(16		)	(16		)	(48		)	(47		)
Amortization of:
Prior service cost (benefit)	(1		)	(1		)	(1		)	(3		)	(2		)	(1		)	(4		)	(3		)
Actuarial loss (gain)	13			23			37			69			(2		)	2			(5		)	6
Net periodic benefit cost (benefit)(a)	$	20		$	31		$	61		$	94		$	(3	)	$	2		$	(6	)	$	7

(a) Includes $2 million and $8 million in total net costs for pension benefits for the three and nine months ended September 30, 2013, respectively, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income. Includes less than $1 million in total net costs for postretirement benefits for both the three and nine months ended September 30, 2013, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income.

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 and nine months ended September 30, 2014, and 2013:

	Pension Benefits								Postretirement Benefits
	Three Months				Nine Months				Three Months					Nine Months
	2014		2013		2014		2013		2014			2013		2014			2013
Ameren Missouri	$	13	$	18	$	38	$	54	$ (a)			$	2	$	2		$	7
Ameren Illinois	7		10		22		31		(3		)	(a)		(7		)	(a)
Other(b)	(a)		3		1		9		(a)			(a)		(1		)	(a)
Ameren(c)	$	20	$	31	$	61	$	94	$	(3	)	$	2	$	(6	)	$	7

(a) Less than $1 million.

(b) Includes $2 million and $8 million in total net costs for pension benefits for the three and nine months ended September 30, 2013, respectively, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income. Includes less than $1 million in total net costs for postretirement benefits for both the three and nine months ended September 30, 2013, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income.

(c) 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, as amended, provides that if the Elgin, Gibson City, and Grand Tower gas-fired energy centers are subsequently sold by Medina Valley and if Medina Valley receives additional proceeds from such sale, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in

excess of the $137.5 million previously paid to Genco.

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 September 30, 2014, consolidated balance sheet in "Other assets." The corresponding

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payable due to Genco is reflected on Ameren's September 30, 2014, consolidated balance sheet in "Other deferred credits and liabilities." 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 for the three and nine months ended September 30, 2014, and 2013:

	Three Months						Nine Months
	2014			2013			2014			2013
Operating revenues	$	—		$	311		$	1		$	878
Operating expenses	(1		)	(309		)	(4		)	(1,034		)	(a)
Operating income (loss)	(1		)	2			(3		)	(156		)
Other income (loss)	—			—			—			(1		)
Interest charges	—			(9		)	—			(31		)
Loss before income taxes	(1		)	(7		)	(3		)	(188		)
Income tax (expense) benefit	—			4			—			(24		)
Loss from discontinued operations, net of taxes	$	(1	)	$	(3	)	$	(3	)	$	(212	)

(a) Included a noncash pretax asset impairment charge of $175 million for the nine months ended September 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell.

Ameren recorded a cumulative pretax charge to earnings of $175 million for the nine months ended September 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. Also, 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. For the nine months ended September 30, 2013, this change in basis resulted in a cumulative discontinued operations deferred tax expense of $96 million. The deferred tax expense was partially offset by the then-expected tax benefits of $72 million related to the pretax loss from discontinued operations including the impairment charge recorded during the nine months ended September 30, 2013.

Ameren’s results of operations for the nine months ended September 30, 2014, include adjustments for the New AER net

working capital amount owed to IPH and for certain contingent liabilities associated with the New AER divestiture. The final working capital adjustment and a portion of the contingent liabilities were paid to IPH in the third quarter of 2014, resulting in a $13 million cash payment. Additionally, Ameren recognized the operating revenues and operating expenses associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers prior to the completion of their sale to Rockland Capital on January 31, 2014. The final tax basis of the AER disposal group and the related tax benefit resulting from the transaction 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 September 30, 2014.

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The following table presents the carrying amounts of the components of assets and liabilities segregated on Ameren's consolidated balance sheets as discontinued operations at September 30, 2014, and December 31, 2013:

	September 30, 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	$	1	$	5
Asset retirement obligations(b)	32		40
Total liabilities of discontinued operations	$	33	$	45

(a) Includes 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 $32 million and $31 million at September 30, 2014, and December 31, 2013, respectively.

Pursuant to the IPH transaction agreement, as amended, Ameren is obligated to pay up to $29 million for certain contingent liabilities as of September 30, 2014, which were included in "Other deferred credits and liabilities" on Ameren's September 30, 2014 consolidated balance sheet.

The note receivable from Marketing Company related to the cash collateral support provided to New AER was $23 million and $18 million at September 30, 2014, and December 31, 2013, respectively, and was reflected on Ameren's consolidated balance sheet in "Other assets." This receivable is due to Ameren, with interest, on December 2, 2015, or sooner as cash collateral requirements are reduced. In addition, as of September 30, 2014, 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 $23 million, which includes $4 million currently covered by Ameren guarantees. This cash collateral support is part of Ameren’s obligation to provide certain limited credit support to New AER until December 2, 2015, as discussed below.

Ameren Guarantees and Letters of Credit

The IPH transaction agreement, as amended, requires Ameren 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 pursuant to which Dynegy will, among other things, guarantee IPH's indemnification obligations until December 2, 2015.

In addition to the $29 million of contingent liabilities recorded on Ameren’s September 30, 2014 consolidated balance sheet, Ameren had a total of $141 million in guarantees outstanding for New AER that were not recorded on Ameren’s September 30, 2014 consolidated balance sheet, which included:

• $132 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 September 30, 2014, Ameren would have been required under its guarantees to provide $4 million to the counterparties.

• $9 million related to requirements for lease agreements and potential environmental obligations. If New AER had not fulfilled its lease obligation as of September 30, 2014, Ameren would have been required to provide approximately $8 million to the leasing counterparty.

Additionally, at September 30, 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 or letters of credit was probable as of September 30, 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

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described in Note 1 - Summary of Significant Accounting Policies. The category called Other primarily includes Ameren (parent) 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 and nine months ended September 30, 2014, and 2013, and total assets of continuing operations as of September 30, 2014, and December 31, 2013.

Three Months	Ameren Missouri		Ameren Illinois		Other			Intersegment Eliminations			Ameren
2014
External revenues	$	1,089	$	572	$	9		$	—		$	1,670
Intersegment revenues	8		—		2			(10		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	222		75		(3		)	—			294
2013
External revenues	$	1,088	$	547	$	3		$	—		$	1,638
Intersegment revenues	5		—		1			(6		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	238		77		(10		)	—			305
Nine Months
2014
External revenues	$	2,793	$	1,864	$	26		$	—		$	4,683
Intersegment revenues	21		1		3			(25		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	395		156		(10		)	—			541
2013
External revenues	$	2,760	$	1,744	$	12		$	—		$	4,516
Intersegment revenues	18		3		2			(23		)	—
Net income (loss) attributable to Ameren Corporation from continuing operations	362		139		(37		)	—			464
As of September 30, 2014:
Total assets	$	13,179	$	7,983	$	810		$	(111	)	$	21,861	(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 September 30, 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 parent company 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 constructing 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 the divestiture transactions.

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 effect of these factors on Ameren’s earnings per share.

OVERVIEW

Net income attributable to Ameren Corporation was $293 million in the third quarter of 2014, compared with $302 million in the third quarter of 2013. Net income attributable to Ameren Corporation from continuing operations was $294 million in the third quarter of 2014, compared with $305 million in the third quarter of 2013. Net income attributable to Ameren Corporation was $538 million in the first nine months of 2014, compared with $252 million in the first nine months of 2013. Net income attributable to Ameren Corporation from continuing operations was $541 million in the first nine months of 2014, compared with $464 million in the first nine months of 2013.

Net income from continuing operations at Ameren was unfavorably affected in the third quarter of 2014, compared with the same period in 2013, by milder summer temperatures, which reduced electric sales volumes. Additionally, earnings decreased in the third quarter and the first nine months of 2014, compared with the same periods in 2013, as a result of higher effective income tax rates and increased depreciation and amortization expenses. Net income from continuing operations was favorably affected in the third quarter and the first nine months of 2014, compared with the same periods in 2013, by increased rates for Ameren Illinois and ATXI electric transmission service and for Ameren Illinois natural gas delivery service, each effective January 1, 2014, as well as decreased interest expense. Net income from continuing operations was also favorably affected in the first nine months of 2014, compared with the same period in 2013, by the absence in 2014 of a reduction in 2013 revenues resulting from the FAC prudence review charge and the timing of the Callaway energy center's refueling and maintenance outages. The 2013 outage occurred during the second quarter while the 2014 outage began in October.

Ameren’s strategic plan includes investing in 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 at both the federal and state level. 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

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Ameren’s strategy, Ameren is investing significant and growing amounts of discretionary capital in Ameren Illinois and ATXI electric transmission service projects and Ameren Illinois energy and natural gas delivery services, because these investments can improve the reliability, safety, and sustainability of the services provided to customers and because these services operate under modern, constructive regulatory frameworks.

As a part of the strategic plan, Ameren Missouri is focused on completing the following three key capital projects: replacing the nuclear reactor vessel head at the Callaway energy center during its current refueling and maintenance outage; installing additional environmental controls at the coal-fired Labadie energy center; and placing into service the O’Fallon solar energy center. These projects are expected to be completed by the end of 2014 so that they, along with two recently completed substations, can meet Ameren Missouri customers’ energy needs and expectations as well as be included in the rate base used to compute the revenue requirement in Ameren Missouri’s current electric service rate case. Ameren Illinois continues to implement its electric and natural gas distribution system modernization action plan, including the installation of advanced electric meters and natural gas meter modules. Ameren Illinois and ATXI continue to invest in FERC-regulated electric transmission projects as a key area of earnings growth for the company, with approximately $375 million invested in the first nine months of 2014. With respect to ATXI’s Illinois Rivers project, construction has started on seven of the ten substations and foundation work on one line segment has begun.

Execution of Ameren’s strategic plan requires successfully managing rate cases to recover and earn fair returns on the investments Ameren makes to benefit its customers, as well as addressing other regulatory matters. Ameren Missouri is focused on achieving a constructive conclusion to the $264 million electric service rate increase request filed in July 2014, which reflects the key capital projects discussed above, among other things. Based on the administrative law judges’ recommendation, Ameren Illinois expects a constructive outcome in its April 2014 ICC annual electric delivery service formula rate update filing, as revised in July 2014. To mitigate rate increases for customers and to maximize value for shareholders, Ameren also remains focused on operational improvement and disciplined cost management.

In November 2013, a customer group filed a complaint case with FERC seeking a reduction in the allowed base return on common equity for FERC-regulated MISO transmission rate base, as well as a limit on the common equity ratio, under the MISO tariff. Currently, the FERC-allowed base return on common equity for MISO transmission owners is 12.38%. In October 2014, FERC issued an order establishing settlement procedures and, if necessary, hearing procedures regarding the allowed base return on common equity and denied all other aspects of the MISO complaint case. This complaint case could result in a reduction to Ameren Illinois' and ATXI's allowed base return on common equity, which would result in a refund for transmission service revenues earned back to the effective refund date of November 12, 2013. In November 2014, we filed a request with FERC to

include an incentive adder of up to 50 basis points for participation in an RTO on the allowed base return on common equity.

Ameren Missouri continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. Ameren Missouri files a non-binding integrated resource plan with the MoPSC every three years. Ameren Missouri filed a 20-year integrated resource plan with the MoPSC in October 2014. The plan presents a long-term approach to transition Ameren Missouri’s generation fleet to a more fuel-diverse portfolio, including the use of solar, wind, natural gas, and nuclear power. The plan includes expanding renewable generation, retiring coal-fired generating capacity as energy centers reach the end of their useful lives, and adding natural gas-fired combined cycle generation. Ameren Missouri continues to study future alternatives, including additional customer energy efficiency programs that could help defer new energy center construction. Ameren Missouri’s integrated resource plan is projected to achieve the carbon emissions reductions proposed in the EPA’s Clean Power Plan by 2035, rather than the EPA’s final target date of 2030, or its interim target dates beginning in 2020, at an anticipated cost that is lower than that which would be incurred to meet the EPA’s target dates. This plan allows for operational flexibility to address changes in customer energy demand, changes in technology, and new regulations, among other things. Additionally, Ameren Missouri’s approach is expected to mitigate potential regional reliability risks. Based on the reduced costs to its customers, the reduced reliability risk, and the flexibility provided, Ameren Missouri is actively advocating for energy policies at both the federal and state levels which support the implementation of its integrated resource plan.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Weather, economic conditions, the effects of customer 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, enriched uranium, natural gas, methane gas, and oil for fuel in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We have natural gas cost recovery mechanisms for our Illinois and Missouri natural gas delivery service businesses, a purchased power cost recovery mechanism for our Illinois electric delivery service business, and a FAC for our Missouri electric utility business. Ameren Illinois' electric delivery service utility business, pursuant to the IEIMA, conducts an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for that year, with recoveries from or refunds to customers made in a subsequent year. Included in Ameren Illinois' revenue requirement reconciliation is a formula for the return on equity, which is equal

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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 is 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 businesses. 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 and nine months ended September 30, 2014, and 2013:

	Three Months				Nine Months
	2014		2013		2014		2013
Net income attributable to Ameren Corporation	$	293	$	302	$	538	$	252
Earnings per common share - diluted	1.20		1.24		2.20		1.03
Net income attributable to Ameren Corporation - continuing operations	294		305		541		464
Earnings per common share - diluted - continuing operations	1.20		1.25		2.21		1.91

Net income attributable to Ameren Corporation from continuing operations decreased $11 million, or 5 cents per diluted share, in the third quarter of 2014 compared with the third quarter of 2013. The decrease in net income attributable to Ameren Corporation from continuing operations between periods was due to a $16 million decrease in net income from the Ameren Missouri segment and a $2 million decrease in net income from the Ameren Illinois segment offset by a $7 million decrease in net loss from Ameren (parent) and nonregistrant subsidiaries.

Net income attributable to Ameren Corporation from continuing operations increased $77 million, or 30 cents per diluted share, in the first nine months of 2014 compared with the same period in 2013. The increase in net income attributable to Ameren Corporation from continuing operations between periods was due to a $33 million increase in net income from the Ameren Missouri segment, a $17 million increase in net income from the Ameren Illinois segment, and a $27 million decrease in net loss from Ameren (parent) and nonregistrant subsidiaries.

Net income from continuing operations at Ameren was favorably affected in the third quarter and the first nine months of 2014, respectively, compared with the same periods in 2013 (except where a specific period is referenced), by:

• the timing of the Callaway energy center's refueling and maintenance outages. The 2013 outage occurred during the second quarter while the 2014 outage began in October (9 cents per share for the nine months ended September 30, 2014);

• an increase in electric transmission earnings under formula ratemaking at Ameren Illinois and ATXI primarily due to additional rate base investment (5 cents per share and 9 cents per share, respectively);

• decreased other operations and maintenance expenses at Ameren (parent) and nonregistrant subsidiaries primarily resulting from the substantial elimination of costs previously incurred in support of the divested merchant generation business (4 cents per share and 7 cents per share, respectively);

• decreased interest expense, primarily due to maturity of higher-cost debt (2 cents per share and 7 cents per share, respectively);

• the absence in 2014 of a reduction in 2013 revenues at Ameren Missouri resulting from the FAC prudence review charge for the estimated obligation to refund to customers amounts associated with sales recognized for the period from October 1, 2009, to May 31, 2011 (1 cent per share and 7 cents per share, respectively);

• higher natural gas rates at Ameren Illinois pursuant to a December 2013 order (1 cent per share and 6 cents per share, respectively); and

• increased electric and natural gas demand in the first nine months of 2014 primarily resulting from colder winter temperatures and warmer early summer temperatures (estimated at 4 cents per share for the nine months ended September 30, 2014).

Net income from continuing operations at Ameren was unfavorably affected in the third quarter and the first nine months of 2014, respectively, compared with the same periods in 2013 (except where a specific period is referenced), by:

• decreased electric demand resulting from milder summer temperatures in the third quarter (estimated at 6 cents per share for the three months ended September 30, 2014);

• an increase in the effective tax rate (4 cents per share and 5 cents per share, respectively);

• increased depreciation and amortization expense primarily resulting from electric distribution capital additions at Ameren Missouri and Ameren Illinois (2 cents per share and 3 cents per share, respectively); and

• increased other operations and maintenance expenses related to Ameren Illinois natural gas delivery service (3 cents per share for the nine months ended September 30, 2014).

The cents per share information presented in the explanations above is based on the diluted average shares outstanding in the third quarter and first nine months of 2013. For

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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 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 and nine months ended September 30, 2014, and 2013:

	Ameren Missouri			Ameren Illinois			Other / Intersegment Eliminations			Ameren
Three Months 2014:
Electric margins	$	815		$	356		$	4		$	1,175
Natural gas margins	14			84			—			98
Other operations and maintenance	(228		)	(185		)	9			(404		)
Depreciation and amortization	(118		)	(66		)	(3		)	(187		)
Taxes other than income taxes	(89		)	(31		)	(1		)	(121		)
Other income (expense)	11			2			1			14
Interest charges	(53		)	(31		)	(1		)	(85		)
Income (taxes) benefit	(129		)	(54		)	(11		)	(194		)
Income (loss) from continuing operations	223			75			(2		)	296
Loss from discontinued operations, net of tax	—			—			(1		)	(1		)
Net income (loss)	223			75			(3		)	295
Preferred dividends	(1		)	—			(1		)	(2		)
Net income (loss) attributable to Ameren Corporation	$	222		$	75		$	(4	)	$	293
Three Months 2013:
Electric margins	$	820		$	336		$	1		$	1,157
Natural gas margins	13			77			(1		)	89
Other revenues	1			—			(1		)	—
Other operations and maintenance	(212		)	(166		)	(5		)	(383		)
Depreciation and amortization	(114		)	(59		)	(2		)	(175		)
Taxes other than income taxes	(91		)	(30		)	—			(121		)
Other income (expense)	14			1			—			15
Interest charges	(43		)	(31		)	(14		)	(88		)
Income (taxes) benefit	(149		)	(51		)	13			(187		)
Income (loss) from continuing operations	239			77			(9		)	307
Loss from discontinued operations, net of tax	—			—			(3		)	(3		)
Net income (loss)	239			77			(12		)	304
Noncontrolling interests and preferred dividends	(1		)	—			(1		)	(2		)
Net income (loss) attributable to Ameren Corporation	$	238		$	77		$	(13	)	$	302
Nine Months 2014:
Electric margins	$	1,972		$	906		$	13		$	2,891
Natural gas margins	59			329			(1		)	387
Other revenues	1			—			(1		)	—
Other operations and maintenance	(677		)	(580		)	21			(1,236		)
Depreciation and amortization	(351		)	(193		)	(7		)	(551		)
Taxes other than income taxes	(248		)	(109		)	(5		)	(362		)
Other income (expense)	35			5			—			40
Interest charges	(159		)	(90		)	(17		)	(266		)
Income (taxes) benefit	(234		)	(110		)	(13		)	(357		)
Income (loss) from continuing operations	398			158			(10		)	546
Loss from discontinued operations, net of tax	—			—			(3		)	(3		)
Net income (loss)	398			158			(13		)	543
Preferred dividends	(3		)	(2		)	—			(5		)
Net income (loss) attributable to Ameren Corporation	$	395		$	156		$	(13	)	$	538
Nine Months 2013:
Electric margins	$	1,919		$	857		$	(1	)	$	2,775
Natural gas margins	58			293			(2		)	349
Other revenues	1			2			(3		)	—
Other operations and maintenance	(686		)	(538		)	(5		)	(1,229		)
Depreciation and amortization	(338		)	(182		)	(8		)	(528		)
Taxes other than income taxes	(247		)	(102		)	(5		)	(354		)
Other income (expense)	34			—			(1		)	33
Interest charges	(159		)	(96		)	(34		)	(289		)
Income (taxes) benefit	(217		)	(93		)	22			(288		)
Income (loss) from continuing operations	365			141			(37		)	469
Loss from discontinued operations, net of tax	—			—			(212		)	(212		)
Net income (loss)	365			141			(249		)	257
Noncontrolling interests and preferred dividends	(3		)	(2		)	—			(5		)
Net income (loss) attributable to Ameren Corporation	$	362		$	139		$	(249	)	$	252

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Margins

The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in the three and nine months ended September 30, 2014, compared with the same periods 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)	$	(18	)	$	(8	)	$	—		$	(26	)
Base rates (estimate)	—			13			—			13
Recovery of FAC under-recovery(c)	(7		)	—			—			(7		)
Off-system sales and transmission services revenues (included in base rates)	21			—			—			21
MEEIA (energy efficiency)	5			—			—			5
Transmission services revenues	—			8			5			13
FAC prudence review charge in 2013	3			—			—			3
Bad debt, energy efficiency programs and environmental remediation cost riders	—			3			—			3
Sales volume (excluding the estimated effect of abnormal weather)	(8		)	—			—			(8		)
Other	5			(3		)	(3		)	(1		)
Total electric revenue change	$	1		$	13		$	2		$	16
Fuel and purchased power change:
Energy costs included in base rates and other	$	(13	)	$	—		$	1		$	(12	)
Recovery of FAC under-recovery(c)	7			—			—			7
Transmission services expenses	—			7			—			7
Total fuel and purchased power change	$	(6	)	$	7		$	1		$	2
Net change in electric margins	$	(5	)	$	20		$	3		$	18
Natural gas margins change:
Base rates (estimate)	$	—		$	5		$	—		$	5
Gross receipts tax	—			(1		)	—			(1		)
Other	1			3			1			5
Net change in natural gas margins	$	1		$	7		$	1		$	9
Nine Months	Ameren Missouri			Ameren Illinois			Other(a)			Ameren
Electric revenue change:
Effect of weather (estimate)(b)	$	19		$	(3	)	$	—		$	16
Base rates (estimate)	—			36			—			36
Recovery of FAC under-recovery(c)	(20		)	—			—			(20		)
Off-system sales and transmission services revenues (included in base rates)	(6		)	—			—			(6		)
MEEIA (energy efficiency)	25			—			—			25
Transmission services revenues	—			24			14			38
FAC prudence review charge in 2013	25			—			—			25
Bad debt, energy efficiency programs and environmental remediation cost riders	—			6			—			6
Illinois pass-through power supply costs	—			(46		)	—			(46		)
Reserve for potential transmission refund	—			(4		)	—			(4		)
Sales volume (excluding the estimated effect of abnormal weather)	(15		)	—			—			(15		)
Other	1			(11		)	(4		)	(14		)
Total electric revenue change	$	29		$	2		$	10		$	41

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	Ameren Missouri		Ameren Illinois		Other(a)		Ameren
Fuel and purchased power change:
Energy costs included in base rates and other	$	4	$	—	$	4	$	8
Recovery of FAC under-recovery(c)	20		—		—		20
Transmission services expenses	—		1		—		1
Illinois pass-through power supply costs	—		46		—		46
Total fuel and purchased power change	$	24	$	47	$	4	$	75
Net change in electric margins	$	53	$	49	$	14	$	116
Natural gas margins change:
Effect of weather (estimate)(b)	$	1	$	5	$	—	$	6
Base rates (estimate)	—		24		—		24
Gross receipts tax	—		3		—		3
Bad debt, energy efficiency programs and environmental remediation cost riders	—		1		—		1
Other	—		3		1		4
Net change in natural gas margins	$	1	$	36	$	1	$	38

(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 energy 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 $18 million, or 2%, and $116 million, or 4%, for the three and nine months ended September 30, 2014, respectively, compared with the same periods in 2013. Ameren's natural gas margins increased by $9 million, or 10%, and $38 million, or 11%, for the three and nine months ended September 30, 2014, respectively, compared with the same periods 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 $5 million and $14 million for the three and nine months ended September 30, 2014, respectively, compared with the same periods in 2013, reflecting increased rate base investment and recoverable costs under forward-looking formula ratemaking.

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 review. Net energy costs include fuel and purchased power costs, including transportation charges and revenues, net of off-system sales. 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 $7 million and $20 million for the three and nine months ended September 30, 2014, respectively, compared with the same periods in 2013, with a corresponding offset to fuel expense to reduce the previously recognized FAC regulatory asset.

Ameren Missouri's electric margins decreased by $5 million, or 1%, for the three months ended September 30, 2014, compared with the same period in 2013. Ameren Missouri’s electric margins increased by $53 million, or 3%, for the nine

months ended September 30, 2014, compared with the same period in 2013. The following items had a favorable effect on Ameren Missouri's electric margins for the three and nine months ended September 30, 2014, compared with the same periods in 2013 (except where a specific period is referenced):

• The absence in 2014 of a reduction in revenues resulting from a July 2013 MoPSC prudence review order. Ameren Missouri recorded a FAC prudence review charge in 2013 for its estimated obligation to refund to its electric customers the earnings associated with sales recognized by Ameren Missouri from October 1, 2009, to May 31, 2011 ($3 million and $25 million, respectively).

• Higher revenues associated with the customer MEEIA energy efficiency program cost recovery mechanism ($1 million and $8 million, respectively) and lost revenue recovery mechanism ($4 million and $17 million, respectively), which increased revenues by a combined $5 million and $25 million, respectively. 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.

• Winter temperatures in 2014 were colder compared to 2013 as heating degree-days increased 12%, for the nine months ended September 30, 2014, compared with the same period in 2013, which resulted in higher sales volumes and an estimated $19 million increase in revenues. Higher sales volumes led to an increase in net energy costs of $2 million. The change in net energy costs is the sum of the change in energy costs included in base rates (+$4 million) and the change in off-system sales and transmission services revenues (-$6 million) in the above table.

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The following items had an unfavorable effect on Ameren Missouri’s electric margins for the three and nine months ended September 30, 2014, compared with the same periods in 2013 (except where a specific period is referenced):

• Summer temperatures for the three months ended September 30, 2014 were milder as cooling degree-days decreased 7%, compared with the same period in 2013, which resulted in reduced sales volumes and an estimated $18 million decrease in revenues. Reduced sales volumes led to a decrease in net energy costs of $8 million. The change in net energy costs is the sum of the change in energy costs included in base rates (-$13 million) and the change in off-system sales and transmission services revenues (+$21 million) in the above table.

• Lower sales volumes primarily caused by the MEEIA programs. Excluding the estimated effect of abnormal weather, total retail sales volumes decreased 1% for both the three and nine months ended September 30, 2014, respectively, compared with the same periods in 2013, which decreased revenues by an estimated $8 million and $15 million, respectively.

Ameren Missouri's natural gas margins increased $1 million, or 8%, and $1 million, or 2%, for the three and nine months ended September 30, 2014, respectively, compared with the same periods in 2013. Ameren Missouri's natural gas margins were favorably affected by winter temperatures that were colder in 2014 compared to 2013 as heating degree-days increased by 12%, for the nine months ended September 30, 2014, compared with the same period in 2013, which increased revenues by an estimated $1 million.

Ameren Illinois

Ameren Illinois has a cost recovery mechanism for power purchased on behalf of its electric customers. These pass-through power supply costs do not affect Ameren Illinois’ electric margins as they are offset by a corresponding amount in revenues.

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 additional information regarding the revenue requirement. If the current year's revenue requirement is greater than the revenue requirement upon which customer rates were based, 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 upon which customer rates were based, 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 $20 million, or 6%, and $49 million, or 6%, for the three and nine months ended September 30, 2014, respectively, compared with the same periods in 2013. The following items had a favorable effect on Ameren Illinois’ electric margins for the three and nine months ended September 30, 2014, compared with the same periods in 2013:

• Electric delivery service formula ratemaking adjustments resulting from the reconciliation of the revenue requirement pursuant to the IEIMA, which increased revenues by an estimated $13 million and $36 million, respectively. The adjustments were primarily caused by increased rate base, and higher recoverable costs.

• Transmission services margin increased $15 million and $25 million, respectively, largely due to a higher transmission services revenue requirement driven primarily by increased rate base investment. The change in transmission services margin is the sum of the change in transmission services revenues (+$8 million and +$24 million, respectively) and the change in transmission services expenses (+$7 million and +$1 million, respectively) in the above table.

• A net increase in recovery of bad debt charge-offs, customer energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms, which increased revenues by $3 million and $6 million, respectively. See Other Operations and Maintenance Expenses in this section for information on a related offsetting net increase in customer energy efficiency and environmental remediation costs.

The following items had an unfavorable effect on Ameren Illinois’ electric margins for the three and nine months ended September 30, 2014, compared with the same periods in 2013 (except where a specific period is referenced):

• The establishment of a reserve for a potential transmission refund based on a June 2014 FERC order, which decreased revenues by $4 million for the nine months ended September 30, 2014, compared with the same period in 2013. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for additional information.

• Summer temperatures in 2014 were milder compared to 2013, as cooling degree-days decreased 14% and 3%, respectively, which decreased revenues by an estimated $8 million and $3 million, respectively.

Ameren Illinois' natural gas margins increased by $7 million, or 9%, and $36 million, or 12%, for the three and nine months ended September 30, 2014, respectively, compared with the same periods in 2013. The following items had a favorable effect on Ameren Illinois’ natural gas margins for the three and nine months ended September 30, 2014, compared with the same periods in 2013 (except where a specific period is referenced):

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• Higher natural gas delivery service rates effective January 2014, which increased revenues by an estimated $5 million and $24 million, respectively.

• Winter temperatures in 2014 were colder compared to 2013 as heating degree-days increased 14% for the nine months ended September 30, 2014, compared with the same period in 2013, which increased revenues by an estimated $5 million.

• Increased gross receipts taxes due primarily to higher natural gas rates and higher sales volumes as a result of colder winter temperatures in 2014, which increased revenues by $3 million for the nine months ended September 30, 2014, compared with the same period in 2013. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.

• A net increase in recovery of bad debt charge-offs, customer energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms, which increased revenues by $1 million for the nine months ended September 30, 2014, compared with the same period in 2013. See Other Operations and Maintenance Expenses in this section for information on a related offsetting net increase in customer energy efficiency and environmental remediation costs.

Other Operations and Maintenance Expenses

Ameren Corporation

Other operations and maintenance expenses were $21 million higher in the third quarter of 2014 and $7 million higher in the first nine months of 2014, as compared with the same periods in 2013. Other operations and maintenance expenses increased $16 million at Ameren Missouri and $19 million at Ameren Illinois in the third quarter of 2014, as compared with the third quarter of 2013. Other operations and maintenance expenses decreased $9 million at Ameren Missouri, but were $42 million higher at Ameren Illinois in the first nine months of 2014, as compared with the first nine months of 2013. In addition to the changes at Ameren Missouri and Ameren Illinois, other corporate operations and maintenance expenses decreased $14 million in the third quarter of 2014 and $26 million in the first nine months of 2014, as compared with the same periods of 2013, primarily due to the substantial elimination of business and administrative costs previously incurred in support of the divested merchant generation business.

Ameren Missouri

Other operations and maintenance expenses were $16 million higher in the third quarter of 2014, as compared with the third quarter of 2013, but were $9 million lower in the first nine months of 2014, as compared with the first nine months of 2013. The following items increased other operations and maintenance expenses for the three and nine months ended September 30, 2014, compared with the year-ago periods (except where a specific period is referenced):

• Higher litigation costs due, in part, to cases discussed in Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report ($5 million and $11 million, respectively).

• An increase in accrued disposal costs of low-level radioactive nuclear waste at the Callaway energy center ($8 million for the nine months ended September 30, 2014).

• An increase in customer energy efficiency program costs due to MEEIA requirements ($1 million and $8 million, respectively). These costs were offset by increased electric revenues from customer billings, with no overall effect on net income.

• Higher labor costs, primarily because of wage increases ($1 million and $8 million, respectively).

• An increase in bad debt expense due to a decreased rate of customer collections ($2 million for the nine months ended September 30, 2014).

• An unfavorable change in unrealized net MTM gains, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans ($3 million and $2 million, respectively).

• An increase in electric distribution maintenance expenditures, primarily related to system repair work ($2 million and $1 million, respectively).

The following items decreased other operations and maintenance expenses for the three and nine months ended September 30, 2014, compared with the year-ago periods (except where a specific period is referenced):

• A reduction in refueling and maintenance costs at the Callaway energy center, primarily due to the timing of outages, as the 2013 outage occurred during the second quarter while the 2014 outage began in October ($34 million for the nine months ended September 30, 2014). The 2013 outage resulted in refueling and maintenance costs of $38 million, as compared with costs of $4 million incurred in the third quarter of 2014 in preparation for the October outage.

• A reduction in energy center costs related to refined coal use ($4 million and $14 million, respectively).

• A decrease in storm-related costs, due to fewer major storms in 2014 ($5 million for the nine months ended September 30, 2014).

Ameren Illinois

Pursuant to the provisions of the IEIMA, recoverable electric delivery service 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

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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 $19 million higher in the third quarter and $42 million higher in the first nine months of 2014, as compared with the same periods in 2013. The following items increased other operations and maintenance expenses for the three and nine months ended September 30, 2014, compared with the year-ago periods (except where a specific period is referenced):

• Higher labor costs, primarily because of wage increases and staff additions to meet enhanced reliability standards and customer service goals ($5 million and $14 million, respectively).

• An increase in electric distribution maintenance expenditures, primarily related to increased system repair and vegetation management work ($3 million and $11 million, respectively).

• Higher expenses related to asbestos claims ($2 million and $7 million, respectively).

• An increase in information technology fees, partially related to the IEIMA ($2 million and $7 million, respectively).

• An increase in customer energy efficiency and environmental remediation costs ($1 million and $6 million, respectively).

• Higher natural gas pipeline integrity compliance expenses ($3 million in both periods).

• An increase in bad debt expense due to the timing of customer collections ($4 million for the third quarter of 2014).

Other operations and maintenance expenses decreased for the three and nine months ended September 30, 2014, compared with the year-ago periods, because of a reduction in employee benefit costs, primarily due to lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets ($6 million and $11 million, respectively).

Depreciation and Amortization

Ameren Corporation

Depreciation and amortization expenses increased by $12 million in the third quarter of 2014, as compared with the third quarter of 2013, and increased by $23 million in the first nine months of 2014, as compared with the first nine months of 2013, primarily due to increased expenses at Ameren Missouri and Ameren Illinois as discussed below.

Ameren Missouri

Depreciation and amortization expenses increased by $4 million and $13 million in the third quarter and the first nine months of 2014, respectively, as compared with the same periods in 2013, primarily because of electric distribution capital additions.

Ameren Illinois

Depreciation and amortization expenses increased by $7 million and $11 million in the third quarter and the first nine months of 2014, respectively, as compared with the same periods in 2013, primarily because of electric distribution capital additions.

Taxes Other Than Income Taxes

Ameren Corporation

Taxes other than income taxes were comparable in the third quarter of 2014 with the third quarter of 2013. Taxes other than income taxes increased by $8 million in the first nine months of 2014, as compared with the first nine months of 2013, primarily due to increased expenses at Ameren Illinois as discussed below.

Ameren Missouri

Taxes other than income taxes decreased by $2 million in the third quarter of 2014, as compared with the third quarter of 2013, primarily due to a decrease in gross receipts taxes as a result of decreased electric sales. These decreased gross receipts taxes were offset by decreased 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. Taxes other than income taxes were comparable in the first nine months of 2014 with the first nine months of 2013.

Ameren Illinois

Taxes other than income taxes were comparable in the third quarter of 2014 with the third quarter of 2013. Taxes other than income taxes increased by $7 million in the first nine months of 2014, as compared with the first nine months of 2013, primarily due to an increase in gross receipts taxes as a result of higher natural gas rates and higher sales volumes and a reduction in the electric distribution tax refund between periods. These increased gross receipts taxes were offset by increased gross receipts tax revenues, with no overall effect on net income.

Other Income and Expenses

Ameren Corporation

Other income, net of expenses, was comparable in the third quarter of 2014 with the third quarter of 2013, and increased by $7 million in the first nine months of 2014, as compared with the first nine months of 2013, primarily due to items at Ameren Missouri and Ameren Illinois as discussed below. See Note 5 - Other Income and Expenses under Part I, Item 1, of this report for additional information.

Ameren Missouri

Other income, net of expenses, decreased by $3 million in the third quarter of 2014, as compared with the third quarter of 2013, primarily due to increased donations. Other income, net of expenses, was comparable in the first nine months of 2014 with

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the first nine months of 2013.

Ameren Illinois

Other income, net of expenses, was comparable in the third quarter of 2014 with the third quarter of 2013. Other income, net of expenses, increased by $5 million in the first nine months of 2014, as compared with the first nine months of 2013, primarily due to increased income from customer-requested construction receipts and increased interest income on both the IEIMA 2013 and 2014 revenue requirement reconciliation regulatory assets. A decrease in allowance for equity funds used during construction due to lower interest rates reduced the favorable effect of the above items.

Interest Charges

Ameren Corporation

Interest charges decreased by $3 million in the third quarter of 2014, as compared with the third quarter of 2013, primarily due to a $12 million reduction in interest charges at Ameren (parent), as a result of the maturity of $425 million of 8.875% senior unsecured notes in May 2014, and a decrease in interest charges associated with uncertain tax positions on potential tax liabilities. Partially offsetting these decreases were increased interest charges at Ameren Missouri as discussed below.

Interest charges decreased by $23 million in the first nine months of 2014, as compared with the first nine months of 2013, primarily due to a $16 million reduction in interest charges at Ameren (parent) as discussed above, and decreased interest charges at Ameren Illinois as discussed below.

Ameren Missouri

Interest charges increased by $10 million in the third quarter of 2014, as compared with the third quarter of 2013, primarily due to an increase in interest charges reflecting the absence in 2014 of a 2013 reduction to interest charges associated with uncertain tax positions that became certain when the IRS issued additional guidance. Interest charges were comparable in the first nine months of 2014 with the first nine months of 2013, as increased interest charges reflecting the absence in 2014 of a 2013 reduction to interest charges associated with uncertain tax positions that became certain when the IRS issued additional guidance was partially offset by lower interest charges from 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. This debt was repaid with proceeds from commercial paper issuances with lower interest rates.

Ameren Illinois

Interest charges were comparable in the third quarter of 2014 with the third quarter of 2013. Interest charges decreased by $6 million in the first nine months of 2014, as compared with the first nine months of 2013. The absence in 2014 of interest applied in 2013 to the regulatory liability for the IEIMA 2012 revenue requirement reconciliation resulted in lower interest

charges. The IEIMA 2013 and 2014 revenue requirement reconciliations were both regulatory assets which resulted in no interest charges. Additionally, the January 2014 redemption of $163 million of pollution control revenue bonds, with various interest rates, decreased interest charges. This debt was repaid with proceeds from commercial paper issuances with lower interest rates.

Income Taxes

The following table presents effective income tax rates for the three and nine months ended September 30, 2014, and 2013:

	Three Months				Nine Months
	2014		2013		2014		2013
Ameren(a)	40	%	38	%	40	%	38	%
Ameren Missouri(a)	37	%	38	%	37	%	37	%
Ameren Illinois(a)	42	%	40	%	41	%	40	%

(a) Based on the current estimate of the annual effective tax rate adjusted to reflect the tax effect of items discrete to the relevant period.

Ameren Corporation

The effective tax rate was higher in the third quarter of 2014, as compared with the third quarter of 2013, primarily due to additional tax expense related to stock-based compensation, lower current year tax benefits from company-owned life insurance, and higher state income taxes. Additionally, the effective tax rate was higher between periods due to lower current year tax benefits from certain property-related temporary differences primarily attributable to the tax treatment of allowance for equity funds used during construction at Ameren Illinois for which deferred tax expense is not recognized in the income statement.

The effective tax rate was higher in the first nine months of 2014, as compared with the first nine months of 2013, primarily due to additional tax expense related to stock-based compensation. This tax rate increase was mitigated by the absence in 2014 of items that increased the effective tax rate in 2013, which included the creation of valuation allowances for charitable contributions and state tax credits, and changes that increased Ameren (parent)’s reserve for uncertain tax positions.

Ameren Missouri

The effective tax rate was lower in the third quarter of 2014, as compared with the third quarter of 2013, primarily due to benefits from tax credits and changes in reserves for uncertain tax positions.

The effective tax rate was comparable in the first nine months of 2014 with the first nine months of 2013.

Ameren Illinois

The effective tax rate was higher in the third quarter and the first nine months of 2014, as compared with the same periods in 2013, primarily because of changes in reserves for uncertain tax positions and lower current year tax benefits from certain

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property-related temporary differences primarily attributable to the allowance for equity funds used during construction for which deferred tax expense is not recognized in the income statement.

Loss from Discontinued Operations, Net of Taxes

During the three and nine months ended September 30, 2013, the loss from discontinued operations, net of taxes, was primarily related to the impairment loss and related income tax effects associated with the then-pending sale of New AER. No material activity was recorded in either 2014 period. See Note 12 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for additional information.

LIQUIDITY AND CAPITAL RESOURCES

Our tariff-based gross margins are our principal source of cash from operating activities. A diversified retail customer mix primarily of rate-regulated residential, commercial, and industrial customers provides us with a reasonably predictable source of cash. In addition to using cash from operating activities, we 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. We may repay our short-term

borrowings with cash from operations or, at our discretion, with long-term borrowings, or, in the case of Ameren Missouri and Ameren Illinois, with equity infusions from Ameren (parent). We expect to make significant capital expenditures through 2018 as we invest in our electric and natural gas utility infrastructure to support overall system reliability, environmental compliance, and other improvements. We intend to finance those capital expenditures with a blend of equity and debt so that we maintain an equity ratio around 50%, assuming constructive regulatory environments. We plan to implement our long-term financing plans for debt, equity, or equity-linked securities to finance our operations appropriately, to fund scheduled debt maturities, and to maintain financial strength and flexibility.

The use of cash from operating activities and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at September 30, 2014. The working capital deficit as of September 30, 2014, was primarily the result of our decision to utilize commercial paper issuances, as opposed to long-term debt. With the 2012 Credit Agreements, Ameren has access to $2.1 billion of credit capacity of which $1.3 billion was available at September 30, 2014.

The following table presents net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2014, and 2013:

	Net Cash Provided By (Used In) 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	$	1,208		$	1,215	$	(7	)	$	(1,351	)	$	(991	)	$	(360	)	$	(8	)	$	(296	)	$	288
Ameren(a) - discontinued operations	(5		)	99		(104		)	139			(42		)	181			—			—			—
Ameren Missouri	660			781		(121		)	(593		)	(506		)	(87		)	(67		)	(323		)	256
Ameren Illinois	396			507		(111		)	(627		)	(456		)	(171		)	231			(50		)	281

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

• An $80 million decrease in cash associated with Ameren Missouri’s under-recovered FAC costs. Deferrals and refunds exceeded recoveries in 2014 by $44 million, while recoveries exceeded deferrals in 2013 by $36 million.

• The 2014 refunds to Ameren Illinois customers of $53 million as required under the provisions of the IEIMA for the 2012 revenue requirement reconciliation adjustment, as compared with no refunds in the first nine months of 2013.

• A $46 million increase in rebate payments provided for customer-installed solar generation at Ameren Missouri.

• A $36 million decrease in natural gas commodity costs collected from customers under the PGAs, primarily related to Ameren Illinois.

• A $32 million decrease caused by changes in Ameren Missouri’s coal inventory levels due to 2013 delivery disruptions from flooding as well as increased coal prices.

• The absence in 2014 of $26 million received in 2013 at Ameren Missouri and Ameren Illinois for storm restoration assistance provided to nonaffiliated utilities primarily in response to Hurricane Sandy.

• A $22 million increase in payments associated with stock-based compensation awards in accordance with the provisions of the 2006 Incentive Plan.

• A $19 million increase in the cost of natural gas held in storage at Ameren Illinois because of increased market prices and timing of injections.

• A net $14 million decrease in returns of collateral posted with counterparties due to changes discussed at Ameren Missouri and Ameren Illinois below.

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• A $14 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 $13 million decrease in previously deferred transmission service costs collected from Ameren Illinois customers.

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

• A $6 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 associated with continuing operations during the first nine months of 2014 compared with the same period in 2013:

• Income tax refunds of $5 million in 2014, compared with income tax payments of $122 million in 2013. Ameren’s net operating loss carryforwards resulted in no consolidated federal income tax payments in 2014 or 2013. However, Ameren’s continuing operations paid amounts to Ameren’s discontinued operations based on the tax allocation agreement.

• Electric and natural gas margins, as discussed in Results of Operations excluding certain noncash items, increased by $97 million. The noncash items were the FAC prudence review charge in 2013, the reserve for potential transmission refund in 2014, and the IEIMA revenue requirement reconciliation adjustments for 2014 and 2013, as the collections from customers for the IEIMA adjustments will occur in a subsequent year.

• A $66 million increase in the collection of customer receivable balances compared to the prior year driven by the timing and amount of revenues in each period.

• A $53 million decrease in pension and postretirement benefit plan contributions resulting from changes in actuarial assumptions and the performance of plan assets.

• A $27 million insurance receipt at Ameren Missouri related to the Taum Sauk incident.

• A $26 million decrease in payments caused by the timing of the Callaway nuclear refueling and maintenance outages at Ameren Missouri.

Ameren’s cash from operating activities associated with discontinued operations decreased in the first nine months of 2014, compared with the first nine months of 2013. The 2013 activity related to the disposed New AER and the Elgin, Gibson City and Grand Tower energy centers. The 2014 activity related to transaction costs and tax payments associated with the Elgin, Gibson City and Grand Tower energy centers.

Ameren Missouri

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

• A $114 million increase in income tax payments resulting primarily from a 2014 payment related to reduced deductions for capitalized expenditures for the 2013 tax year offset by the use of net operating loss carryforwards.

• An $80 million decrease in cash associated with under-recovered FAC costs. Deferrals and refunds exceeded recoveries in 2014 by $44 million, while recoveries exceeded deferrals in 2013 by $36 million.

• A $46 million increase in rebate payments provided for customer-installed solar generation.

• A $32 million decrease caused by changes in coal inventory levels due to 2013 delivery disruptions from flooding as well as increased coal prices.

• An $11 million decrease in natural gas commodity costs collected from customers under the PGA.

• The absence in 2014 of $10 million received in 2013 for storm restoration assistance provided to nonaffiliated utilities primarily in response to Hurricane Sandy.

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

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

• A $79 million increase in the collection of customer receivable balances compared to the prior year driven by the timing and amount of revenues in each period.

• Electric and natural gas margins, as discussed in Results of Operations excluding the noncash FAC prudence review charge in 2013, increased by $29 million.

• A $27 million insurance receipt related to the Taum Sauk incident.

• A $26 million decrease in payments caused by the timing of the Callaway nuclear refueling and maintenance outages.

• A $23 million decrease in pension and postretirement benefit plan contributions resulting from changes in actuarial assumptions and the performance of plan assets.

• A net $6 million increase in returns of collateral posted predominately to support exchange activity, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes as well as the effect of credit rating upgrades.

Ameren Illinois

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

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• The 2014 refunds to customers of $53 million as required under the provisions of the IEIMA for the 2012 revenue requirement reconciliation adjustment, as compared with no refunds in the first nine months of 2013.

• A $25 million decrease in natural gas commodity costs collected from customers under the PGA.

• A net $20 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 $19 million increase in the cost of natural gas held in storage because of increased market prices and timing of injections.

• The absence in 2014 of $16 million received in 2013 for storm restoration assistance provided to nonaffiliated utilities primarily in response to Hurricane Sandy.

• A $15 million decrease in the collection of customer receivable balances compared to the prior year driven by the timing and amount of revenues in each period.

• A $14 million increase in labor costs, primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals.

• A $13 million decrease in previously deferred transmission service costs collected from customers.

• A $6 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 nine months of 2014, compared with the same period in 2013:

• Electric and natural gas margins, as discussed in Results of Operations excluding certain noncash items, increased by $53 million. The noncash items were the reserve for potential transmission refund in 2014 and the IEIMA revenue requirement reconciliation adjustments for 2014 and 2013, as the collections from customers for those adjustments will occur in a subsequent year.

• A $16 million increase in income tax refunds resulting primarily from reduced accelerated depreciation deductions and the use of net operating loss carryforwards.

• A $15 million decrease in pension and postretirement benefit plan contributions resulting from changes in actuarial assumptions and the performance of plan assets.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities associated with continuing operations increased in the first nine months of 2014, compared with the same period in 2013. Capital expenditures increased $367 million as a result of both the activity at the registrant subsidiaries discussed below and a $96 million increase at ATXI related to the Illinois Rivers project. In addition, cash used in investing activities increased by a net $5 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 certain limited 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 in January 2014, offset by payment of $13 million to IPH for the final working capital adjustment and a portion of certain contingent liabilities associated with the New AER divestiture. The net proceeds were available to fund continuing operations. During the first nine months of 2013, Ameren’s cash used in investing activities associated with discontinued operations was for capital expenditures.

Ameren Missouri’s cash used in investing activities increased during the first nine months of 2014, compared with the same period in 2013, due to increased capital expenditures of $68 million primarily for reliability and energy center projects, including the Callaway nuclear reactor vessel head replacement project, the Labadie electrostatic precipitator upgrades, and the O’Fallon solar energy center project, offset by a reduction in storm restoration expenditures. In addition, cash used in investing activities increased $24 million due to the absence in 2014 of money pool advance repayments that were received in 2013.

Ameren Illinois’ cash used in investing activities increased during the first nine months of 2014, compared with the same period in 2013, due to an increase in capital expenditures of $171 million primarily for transmission, reliability, 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, we continually review the reliability of our 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 material losses. Compliance with environmental regulations could also have significant impacts on the level of capital expenditures. See Note 9 - Commitments and Contingencies in Part I, Item 1, of this report for additional information.

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Cash Flows from Financing Activities

In the first nine months of 2014, Ameren (parent), Ameren Missouri, and Ameren Illinois utilized lower-cost commercial paper issuances to repay or redeem, in part, higher cost long-term indebtedness and reduce interest expense. Ameren Missouri and Ameren Illinois also reduced interest expense by repaying or redeeming existing long-term indebtedness with higher interest rates, in part, with net proceeds from the issuance of long-term debt with lower interest rates.

Ameren’s financing activities associated with continuing operations used net cash of $8 million during the first nine months of 2014, compared to $296 million during the first nine months of 2013. Amerenutilized net proceeds from net commercial paper issuances of $385 million and long-term debt issuances of $598 million from registrant subsidiaries to repay existing Ameren (parent) long-term indebtedness of $425 million, and to fund the redemption and/or repayment of existing registrant subsidiary long-term indebtedness described below, and to fund, in part, investing activities. In comparison, Ameren had no debt financing activity during the same period in 2013. Dividends paid during the first nine months of 2014 were comparable to dividends paid during the first nine months of 2013.

Cash from financing activities was not necessary to meet the working capital and investing activity needs of our discontinued operations during the first nine months of 2014 and 2013.

Ameren Missouri’s financing activities used cash of $67 million during the first nine months of 2014, compared to $323 million during the first nine months of 2013. In the first nine months of 2014, Ameren Missouri used net proceeds from net commercial paper issuances of $65 million and the issuance of $350 million of senior secured notes to repay at maturity long-term indebtedness of $104 million, repay net money pool borrowings of $105 million, and to fund, in part, investing activities. Ameren Missouri also paid common stock dividends of $268 million in the first nine months of 2014. In comparison, Ameren Missouri paid common stock dividends of $320 million and had no debt financing activity during the same period in 2013.

Ameren Illinois’ financing activities provided net cash of $231 million during the first nine months of 2014, compared with the first nine months of 2013, when financing activities used cash of $50 million. During the first nine months of 2014, Ameren Illinois used net proceeds from net commercial paper issuances of $189 million and the issuance of $250 million of senior secured notes to redeem existing long-term indebtedness of $163 million and repay money pool borrowings. In comparison, Ameren Illinois had minimal debt financing activity during the first nine months of 2013. Ameren Illinois did not pay common stock dividends during the nine months ended September 30, 2014, compared to dividend payments of $45 million during the same period in 2013.

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 September 30, 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)		(753		)
Less: Letters of credit(a)		(b)		(13		)
Total		$	2,100	$	1,334

(a) As of September 30, 2014, $9 million of the letters of credit relate to Ameren's 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, Ameren Missouri’s and Ameren Illinois’ 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. The 2012 Illinois Credit Agreement is available to support issuances under Ameren Illinois’ commercial paper program. During 2014, issuances under

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the Ameren, Ameren Missouri and Ameren Illinois 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 authorizing Ameren Missouri to issue up to $1 billion of short-term debt securities through March 16, 2016. In September 2014, FERC issued an order authorizing Ameren Illinois to issue up to

$1 billion of short-term debt securities through September 15, 2016.

The issuance of short-term debt securities by Ameren is not subject to approval by any regulatory body.

The Ameren Companies continually evaluate the adequacy and appropriateness of their liquidity arrangements given changing business conditions. When business conditions warrant, changes may be made to existing credit agreements or to other short-term borrowing arrangements.

Long-term Debt and Equity

The following table presents the issuances (net of any issuance discounts), redemptions, or maturities of long-term debt for the Ameren Companies for the nine months ended September 30, 2014, and 2013. The Ameren Companies did not have any issuances of common stock during the first nine months of 2014 or 2013. For additional information, see Note 4 - Long-term Debt under Part I, Item 1, of this report.

		Nine Months
	Month Issued, Redeemed or Matured	2014		2013
Issuances
Long-term debt
Ameren Missouri:
3.50% Senior secured notes due 2024	April	$	350	$	—
Ameren Illinois:
4.30% Senior secured notes due 2044	June	248		—
Total Ameren long-term debt issuances		$	598	$	—
Redemptions and Maturities
Long-term debt
Ameren (parent):
8.875% Senior unsecured notes due 2014	May	425		—
Ameren Missouri:
5.50% Senior secured notes due 2014	May	104		—
Ameren Illinois:
5.90% Series 1993 due 2023(a)	January	32		—
5.70% 1994A Series due 2024(a)	January	36		—
5.95% 1993 Series C-1 due 2026	January	35		—
5.70% 1993 Series C-2 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 and maturities		$	692	$	—

(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 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 September 30, 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 cash generated from our operating activities. Inability to raise capital on reasonable terms, particularly during

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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 $291 million, or $1.20 per share, during the first nine months of 2014 and 2013.

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 but considers 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 October 10, 2014, Ameren’s board of directors declared a quarterly common stock dividend of 41 cents per share payable on December 31, 2014, to stockholders of record at the close of business on December 10, 2014, resulting in an annualized equivalent dividend rate of $1.64 per share. The previous annualized equivalent dividend rate was $1.60 per share.

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 September 30, 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.

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 nine months ended September 30, 2014, and 2013:

	Nine Months
	2014		2013
Ameren Missouri	$	268	$	320
Ameren Illinois	—		45
Ameren	291		291

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

Contractual Obligations

For a complete listing of our obligations and commitments, see 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 September 30, 2014, total other obligations related to commitments for coal, natural gas, nuclear fuel, purchased power, methane gas, equipment, customer energy efficiency program expenditures and meter reading services, among other agreements, at Ameren, Ameren Missouri and Ameren Illinois were $5,507 million, $3,725 million, and $1,732 million, respectively.

Off-Balance-Sheet Arrangements

At September 30, 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+
Commercial paper	P-2	A-2	F2

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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 September 30, 2014, were $10 million, $10 million, and $- 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 September 30, 2014. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at September 30, 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 $113 million, $57 million, and $56 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments at current credit ratings. If market prices were 15% higher than September 30, 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 September 30, 2014 levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri or Ameren Illinois could be required to post additional collateral or other assurances for certain trade obligations up to $9 million, $1 million, and $8 million, respectively.

The balance of Marketing Company’s note payable to Ameren for cash collateral requirements was $23 million at September 30, 2014. This balance will vary until December 2, 2015, as cash collateral requirements for New AER will change. Ameren’s obligation to provide credit support on behalf of New AER will cease on December 2, 2015. Changes in commodity prices could trigger additional collateral postings and prepayments for New AER and thus affect the balance of the note. If market prices were 15% higher than September 30, 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 $85 million. If market prices were 15% lower than September 30, 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 $25 million. In addition, as of September 30, 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 $23 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 Illinois Rivers project. ATXI is in the early stages of construction on the Illinois Rivers project. 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 ATXI is pursuing that have been approved by MISO. These two projects are expected to be completed in 2018. In the third quarter of 2014, ATXI filed a request for a certificate of public convenience and necessity and project approval from the ICC for the Spoon River project. 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. In early 2015, ATXI expects to update the estimated cost of the Illinois Rivers project incorporating the final route approved by the ICC, which is longer than originally proposed.

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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. This Ameren Illinois estimate could also be impacted by the final route of the Illinois Rivers project.

• 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 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. In September 2014, Ameren Illinois filed for approval from the ICC to utilize the rate rider mechanism. A decision from the ICC is expected in 2014. Ameren Illinois expects to begin including investments under this regulatory framework in 2015.

• 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 and rate base growth.

• 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. The ICC decision issued in December 2013 established new rates that became effective January 1, 2014. These rates have affected, and will continue to affect, Ameren Illinois' cash receipts 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 is reflected as a regulatory asset and will be collected from customers in 2016.

• 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, as revised in July 2014, will result in a $205 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. In August 2014, the ICC staff submitted its revised calculation of the revenue requirement included in Ameren Illinois’ update filling. The ICC staff recommended a

$205 million increase in Ameren Illinois’ electric delivery service revenue requirement. Other intervenors requested an electric delivery service revenue requirement up to $7 million lower than the revenue requirement recommended by the ICC staff. In October 2014, the administrative law judges issued a proposed order that reflected an increase to Ameren Illinois’ electric delivery service revenue requirement of $204 million. A final 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 receipts 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 July 2014, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $264 million. The rate request seeks recovery of increased net energy costs and rebates provided for customer-installed solar generation, as well as recovery of and a return on additional electric infrastructure investments made for the benefit of Ameren Missouri’s customers. Plant additions to rate base since the last electric rate order are expected to total approximately $1.4 billion through the true-up date in this rate case and include electric infrastructure investments for upgrades to the electrostatic precipitators at the coal-fired Labadie energy center, the replacement of the nuclear reactor vessel head at the Callaway energy center, two new substations in St. Louis, and the O’Fallon solar energy center, among other additions. Approximately $127 million of the request relates to an increase in net energy costs above the current levels included in base rates previously authorized by the MoPSC in its December 2012 electric rate order, 95% of which, absent initiation of this general rate proceeding, would have been reflected in rate adjustments implemented under Ameren Missouri’s existing FAC. The electric rate increase request is based on a 10.4% return on common equity, a capital structure composed of 51.6% common equity, an electric rate base for Ameren Missouri of $7.3 billion, and a test year ended March 31, 2014, with certain pro-forma adjustments expected through the true-up date of December 31, 2014. The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months and a decision by the MoPSC in such proceeding is expected by May 2015, with rates effective by June 2015.

• 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 additional

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customer 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 and higher property and income taxes, among other things.

• Ameren and Ameren Missouri also are pursuing recovery from an insurer, 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 claim of $41 million as of September 30, 2014, is not paid.

• Ameren Missouri's scheduled refueling and maintenance outage at its Callaway energy center began on October 11, 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 expects to incur maintenance costs of $35 million to $40 million relating to the fall 2014 refueling and maintenance outage.

• Ameren Missouri continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. Ameren Missouri files a non-binding integrated resource plan with the MoPSC every three years. Ameren Missouri’s integrated resource plan filed with the MoPSC in October 2014 is a 20-year plan that supports a more fuel-diverse energy portfolio in Missouri, including solar, wind, natural gas and nuclear power. The plan includes expanding renewable generation, retiring coal-fired generating capacity as energy centers reach the end of their useful lives, and adding natural gas-fired combined cycle generation. Ameren Missouri continues to study future alternatives, including additional customer energy efficiency programs that could help defer new energy center construction. Ameren Missouri’s integrated resource plan is projected to achieve the carbon emissions reductions proposed in the EPA’s Clean Power Plan by 2035, rather than the EPA’s final target date of 2030 or its interim target dates beginning in 2020.

• Ameren Missouri continues to evaluate its potential compliance plans for the proposed Clean Power Plan. Based on preliminary studies, if the proposed rules were to be made final, Ameren Missouri anticipates new or accelerated capital expenditures and increased fuel costs would be required to achieve compliance. As proposed, the Clean Power Plan would require the states, including

Missouri and Illinois, to submit compliance plans as early as 2016. The states’ compliance plans may require Ameren Missouri to construct combined cycle gas-fired and renewable energy centers, currently estimated to cost approximately $2 billion by 2020, that Ameren Missouri believes would otherwise not be necessary to meet the energy needs of its customers. Additionally, Missouri’s implementation of the proposed rules, if adopted, could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and gas-fired energy centers.

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

• As of September 30, 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 is made.

• 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. Based on the projected rates that will become effective on January 1, 2015, Ameren Illinois’ 2015 revenue requirement for its electric transmission business is expected to increase by $40 million over the 2014 revenue requirement due to rate base growth. Ameren Illinois’ transmission revenue requirement was based on a 12.38% return on equity, a capital structure composed of approximately 54% common equity, and a rate base of $890 million. Based on the projected rates that become effective on January 1, 2015, ATXI’s 2015 revenue requirement for its electric transmission business is expected to increase by $46 million over the 2014 revenue requirement due to rate base growth, primarily relating to the Illinois Rivers project. ATXI’s transmission revenue requirement was based on a 12.38% return on equity, a capital structure composed of approximately 56% common equity, and a rate base of $536 million.

• In November 2013, a customer group filed a complaint case with FERC seeking a reduction in the allowed base 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 base return on common equity for MISO transmission owners is 12.38%. In October 2014, FERC issued an order establishing settlement procedures and, if necessary, hearing procedures regarding the allowed base return on common equity and denied all other aspects of the

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MISO complaint case. This complaint case could result in a reduction to Ameren Illinois' and ATXI's allowed base return on common equity, which would result in a refund for transmission service revenues earned back to the effective refund date of November 12, 2013. In October 2014, FERC issued an order which confirmed its June 2014 order reducing the allowed base return on common equity for New England transmission owners from 11.14% to 10.57%, with rate incentives allowed up to 11.74%. If our allowed base return on equity was lowered to 10.57%, as established in the New England transmission owners’ case, with no additional rate incentives, the required refund for Ameren and Ameren Illinois would be $14 million and $11 million, respectively, from the refund effective date of November 12, 2013 through September 30, 2014. The estimated annual reduction in revenues if the MISO allowed base return on common equity was 10.57% for Ameren and Ameren Illinois would be $16 million and $12 million, respectively. Ameren Missouri would not expect that a reduction in the FERC-allowed base return on common equity for MISO transmission owners would be material to its results of operations, financial position or liquidity.

• The civil unrest that occurred during the third quarter of 2014 in Ferguson, Missouri, which is located in Ameren Missouri's territory, had a very minor impact on operations and no material impact on our financial condition or results of operations. We are unable to predict if any further civil unrest will have an impact on our financial condition or results of operations. 

• 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

• We seek to maintain access to the capital markets at commercially attractive rates in order to fund our businesses. We seek to enhance regulatory frameworks and returns in order to improve liquidity, credit metrics, and related access to capital.

• The use of cash from operating activities and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit, defined as current liabilities exceeding current assets, as was the case for Ameren and Ameren Illinois at September 30, 2014. The working capital deficit as of September 30, 2014, was primarily the result of Ameren’s decision to utilize commercial paper issuances, as opposed to long-term debt. With the 2012 Credit Agreements, Ameren has access to $2.1 billion of credit capacity of which $1.3 billion was available at September 30, 2014.

• Ameren Illinois expects to issue long-term debt during the fourth quarter of 2014, to reduce commercial paper borrowings.

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

• As of September 30, 2014, Ameren had $292 million in tax benefits from federal and state net operating loss carryforwards (Ameren Missouri – $3 million and Ameren Illinois – $58 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 help reduce or eliminate Ameren's need to issue additional equity to fund these investments through 2018.

• Ameren has entered into an agreement with a buyer to sell the Meredosia energy center in 2015, 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.

• We 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. We expect to extend the term of our multiyear credit agreements to 2019. We believe that our liquidity is adequate given their expected cash from operating activities, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect our ability to execute our expected operating, capital, or financing plans.

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

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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, commodity price risk, and commodity supplier 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. See the discussion below regarding the percentage of commodities required for our businesses that are price-hedged as of September 30, 2014.

Commodity Price Risk

The following table presents, as of September 30, 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	%	92	%	64	%
Coal transportation	100		99		81
Nuclear fuel	100		100		78
Natural gas for generation	—		15		3
Natural gas for distribution(a)	68		20		6
Purchased power for Ameren Illinois(b)	100		62		15
Ameren Missouri:
Coal	100	%	92	%	64	%
Coal transportation	100		99		81
Nuclear fuel	100		100		78
Natural gas for generation	—		15		3
Natural gas for distribution(a)	77		30		15
Ameren Illinois:
Natural gas for distribution(a)	66	%	18	%	5	%
Purchased power(b)	100		62		15

(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, nuclear fuel, and purchased power.

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 and nine months ended September 30, 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.

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Three Months Ended September 30, 2014	Ameren Missouri			Ameren Illinois			Ameren
Fair value of contracts at beginning of period, net	$	8		$	(123	)	$	(115	)
Contracts realized or otherwise settled during the period	(3		)	5			2
Changes in fair values attributable to changes in valuation technique and assumptions	—			—			—
Fair value of new contracts entered into during the period	(2		)	—			(2		)
Other changes in fair value	(10		)	(26		)	(36		)
Fair value of contracts outstanding at end of period, net	$	(7	)	$	(144	)	$	(151	)
Nine Months Ended September 30, 2014
Fair value of contracts at beginning of year, net	$	9		$	(153	)	$	(144	)
Contracts realized or otherwise settled during the period	(16		)	28			12
Changes in fair values attributable to changes in valuation technique and assumptions	—			—			—
Fair value of new contracts entered into during the period	4			—			4
Other changes in fair value	(4		)	(19		)	(23		)
Fair value of contracts outstanding at end of period, net	$	(7	)	$	(144	)	$	(151	)

The following table presents maturities of derivative contracts as of September 30, 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	$	(4	)	$	(1	)	$	—		$	—		$	(5	)
Level 2(a)	(2		)	(1		)	(1		)	—			(4		)
Level 3(b)	3			(1		)	—			—			2
Total	$	(3	)	$	(3	)	$	(1	)	$	—		$	(7	)
Ameren Illinois:
Level 1	$	—		$	—		$	—		$	—		$	—
Level 2(a)	(16		)	(5		)	—			—			(21		)
Level 3(b)	(8		)	(17		)	(18		)	(80		)	(123		)
Total	$	(24	)	$	(22	)	$	(18	)	$	(80	)	$	(144	)
Ameren:
Level 1	$	(4	)	$	(1	)	$	—		$	—		$	(5	)
Level 2(a)	(18		)	(6		)	(1		)	—			(25		)
Level 3(b)	(5		)	(18		)	(18		)	(80		)	(121		)
Total	$	(27	)	$	(25	)	$	(19	)	$	(80	)	$	(151	)

(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. 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 September 30, 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 September 30, 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, other than as described in the next paragraph.

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In July 2014, we implemented a new general ledger and related systems. The new systems provide operational and internal control benefits, including increased support from the system providers, enhanced system security and the automation of previously manual controls. The implementation of the new general ledger and related systems was driven by a need to update our business processes.

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, and Note 10 - Callaway Energy Center, under Part I, Item 1, of this report or Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K and incorporated herein by reference, include the following:

• Ameren Missouri’s electric rate case filed with the MoPSC in July 2014, including the rate shift request filed by the MoOPC, the MIEC and other parties;

• Ameren Illinois’ annual electric delivery service formula rate update filed with the ICC in April 2014;

• Ameren Illinois' appeals of the ICC's December 2013 electric rate order and natural gas rate order;

• Ameren Illinois’ request for rehearing of a September 2014 FERC order requiring refunds to wholesale customers;

• ATXI’s request for a certificate of public convenience and necessity and project approval from the ICC for the Spoon River project;

• Entergy's appeal of a May 2012 FERC 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 June 2014 orders, the appeal filed with the United States Court of Appeals for the District of Columbia Circuit, and settlement procedures regarding a potential electric transmission rate refund;

• the complaint case filed with FERC by a customer group seeking a reduction in the allowed base return on common equity under the MISO tariff;

• 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 the Ameren Companies.

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.

Ameren, Ameren Missouri and Ameren Illinois did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from July 1, 2014 to September 30, 2014.

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ITEM 6. EXHIBITS.

The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.

Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
Material Contracts
10.1	Ameren Companies	Revised Schedule I to Second Amended and Restated Change of Control Severance Plan, as amended
Statement re: Computation of Ratios
12.1	Ameren	Ameren's Statement of Computation of Ratio of Earnings to Fixed Charges
12.2	Ameren Missouri	Ameren Missouri's Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.3	Ameren Illinois	Ameren Illinois’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
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

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.

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: November 10, 2014

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