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 ~~June~~September 30, 2016



¨	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 ~~July 29,~~October 31, 2016, 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	3937
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5958
Item 4.	Controls and Procedures	6059

PART II Other Information

Item 1.	Legal Proceedings	6160
Item 1A.	Risk Factors	6160
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	6160
Item 6.	Exhibits	6261

Signatures		6362

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

GLOSSARY OF TERMS AND ABBREVIATIONS

We use the words “our,” “we” or “us” with respect to certain information that relates to Ameren, Ameren Missouri, and Ameren Illinois, collectively. When appropriate, subsidiaries of Ameren Corporation are named specifically as their various business activities are discussed. Refer to the Form 10-K for a complete listing of glossary terms and abbreviations. Only new or significantly changed terms and abbreviations are included below.

Form 10-K – The combined Annual Report on Form 10-K for the year ended December 31, 2015, filed by the Ameren Companies with the SEC.

MEEIA 2013 – Ameren Missouri’s portfolio of customer energy efficiency programs, net shared benefits, and performance incentive for 2013 through 2015, as approved by the MoPSC in August 2012.

MEEIA 2016 – Ameren Missouri’s portfolio of customer energy efficiency programs, throughput disincentive, and performance incentive for March 2016 through February 2019, as approved by the MoPSC in February 2016.

MoOPC – Missouri Office of Public Counsel.

New Madrid Smelter – Aluminum smelter located in southeast Missouri that was formerly owned by Noranda. Noranda sold the New Madrid Smelter to ARG International AG in October 2016.

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 those that may result from the complaint ~~cases~~case filed in February 2015 with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff, Ameren Missouri’s July 2016 electric rate case filing, Ameren Missouri's appeal of a MoPSC order that clarified the method applied to determine an input used to calculate its performance incentive under MEEIA 2013, Ameren Illinois’ April 2016 annual electric distribution service formula

rate update filing, and future regulatory, judicial, or legislative actions that 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 Ameren Illinois' results of operations, financial position, and liquidity;~~IEIMA;

our ability to align our overall spending, both operating and capital, with regulatory frameworks established by our regulators in an attempt to earn our allowed return on equity;

the effects of changes in federal, state or local laws and other governmental actions, including monetary, fiscal, tax, and energy policies;

the effects of changes in federal, state, or local tax laws, regulations, interpretations, or rates and any challenges to the tax positions taken by the Ameren Companies;

the effects on demand for our services resulting from technological advances, including advances in customer energy efficiency and ~~distributed~~private generation sources, which generate electricity at the site of consumption and are becoming more cost-competitive;

the effectiveness of Ameren Missouri's customer energy efficiency programs and the related ~~amount of any~~ revenues and performance ~~incentive~~incentives earned under its MEEIA ~~2013, MEEIA 2016, and any future MEEIA plan;~~plans;

the timing of increasing capital expenditure and operating expense requirements and our ability to recover these costs in a timely manner;

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 and our customers' tolerance for the related rate increases;

disruptions in the delivery of fuel, failure of our fuel suppliers to provide adequate quantities or quality of fuel, or lack of adequate inventories of fuel, including ultra-low-sulfur coal used for Ameren Missouri’s compliance with environmental regulations;

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

the ability to obtain sufficient insurance, including insurance relating to Ameren Missouri’s Callaway energy center, ~~and insurance for cyber attacks,~~ or, in the absence of insurance, the ability to recover uninsured losses from our customers;

business and economic conditions, including their impact on key customers, interest rates, collection of our receivable balances, and demand for our products;

~~Noranda's bankruptcy filing, the idling of~~suspended operations at ~~its aluminum smelter located in southeast Missouri,~~the New Madrid Smelter, and the resulting impacts to Ameren Missouri's ability to recover its revenue requirement ~~until rates are adjusted by the MoPSC~~ in ~~Ameren Missouri’s~~its July 2016 electric rate case and future rate cases to accurately reflect ~~Noranda’s~~the New Madrid Smelter’s actual sales volumes;

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;

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

the impact of adopting new accounting guidance and the application of appropriate accounting rules and guidance;

~~the 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;

the construction, installation, performance, and cost recovery of generation, transmission, and distribution assets;

the effects of breakdowns or failures of equipment in the operation of natural gas distribution and transmission systems and storage facilities, such as leaks, explosions and mechanical problems, and compliance with natural gas safety regulations;

the effects of our increasing investment in electric transmission projects, our ability to obtain all of the necessary approvals to complete the projects, and the uncertainty as to whether we will achieve our expected returns in a timely manner;

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 CO₂, 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 Ameren Missouri’s 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, work force 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;

legal and administrative proceedings;

the impact of cyber attacks, which could result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the loss of data, such as ~~utility~~ customer data and account information; and

acts of sabotage, war, terrorism, or other intentionally disruptive acts.

New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to

which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement. Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF INCOME

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


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015		2016		2015		2016		2015
Operating Revenues:
Electric	$	1,274	$	1,250	$	2,376	$	2,393	$	1,725	$	1,700	$	4,101	$	4,093
Gas	153		151		485		564		134		133		619		697
Total operating revenues	1,427		1,401		2,861		2,957		1,859		1,833		4,720		4,790
Operating Expenses:
Fuel	166		205		369		411		205		259		574		670
Purchased power	135		101		273		240		178		153		451		393
Gas purchased for resale	41		46		193		282		34		38		227		320
Other operations and maintenance	435		427		835		828		411		428		1,246		1,256
Provision for Callaway construction and operating license (Note 2)	—		69		—		69		—		—		—		69
Depreciation and amortization	210		200		417		393		211		201		628		594
Taxes other than income taxes	115		116		229		241		129		128		358		369
Total operating expenses	1,102		1,164		2,316		2,464		1,168		1,207		3,484		3,671
Operating Income	325		237		545		493		691		626		1,236		1,119
Other Income and Expense:
Miscellaneous income	16		16		36		35		18		19		54		54
Miscellaneous expense	6		6		13		17		8		5		21		22
Total other income	10		10		23		18		10		14		33		32
Interest Charges	95		89		190		177		97		87		287		264
Income Before Income Taxes	240		158		378		334		604		553		982		887
Income Taxes	92		59		123		125		233		208		356		333
Income from Continuing Operations	148		99		255		209		371		345		626		554
Income from Discontinued Operations, Net of Taxes	—		52		—		52		—		—		—		52
Net Income	148		151		255		261		371		345		626		606
Less: Net Income from Continuing Operations Attributable to Noncontrolling Interests	1		1		3		3		2		2		5		5
Net Income Attributable to Ameren Common Shareholders:
Continuing Operations	147		98		252		206		369		343		621		549
Discontinued Operations	—		52		—		52		—		—		—		52
Net Income Attributable to Ameren Common Shareholders	$	147	$	150	$	252	$	258	$	369	$	343	$	621	$	601

Earnings per Common Share – Basic and Diluted:
Earnings per Common Share – Basic:
Continuing Operations	$	0.61	$	0.40	$	1.04	$	0.85	$	1.52	$	1.42	$	2.56	$	2.27
Discontinued Operations	—		0.21		—		0.21		—		—		—		0.21
Earnings per Common Share – Basic and Diluted	$	0.61	$	0.61	$	1.04	$	1.06
Earnings per Common Share – Basic									$	1.52	$	1.42	$	2.56	$	2.48

Earnings per Common Share – Diluted:
Continuing Operations									$	1.52	$	1.41	$	2.56	$	2.26
Discontinued Operations									—		—		—		0.21
Earnings per Common Share – Diluted									$	1.52	$	1.41	$	2.56	$	2.47

Dividends per Common Share	$	0.425	$	0.41	$	0.85	$	0.82	$	0.425	$	0.41	$	1.275	$	1.23
Average Common Shares Outstanding – Basic	242.6		242.6		242.6		242.6		242.6		242.6		242.6		242.6
Average Common Shares Outstanding – Diluted									242.9		243.9		243.0		243.8

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

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Unaudited) (In millions)


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015		2016		2015		2016			2015		2016		2015
Income from Continuing Operations	$	148	$	99	$	255	$	209	$	371		$	345	$	626	$	554
Other Comprehensive Income from Continuing Operations, Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes of $3, $4, $4, and $4, respectively	4		4		2		4
Pension and other postretirement benefit plan activity, net of income taxes of $-, $-, $4, and $4, respectively									(1		)	—		1		4
Comprehensive Income from Continuing Operations	152		103		257		213		370			345		627		558
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests	1		1		3		3		2			2		5		5
Comprehensive Income from Continuing Operations Attributable to Ameren Common Shareholders	151		102		254		210		368			343		622		553

Income from Discontinued Operations, Net of Taxes	—		52		—		52
Other Comprehensive Income from Discontinued Operations, Net of Taxes	—		—		—		—
Comprehensive Income from Discontinued Operations Attributable to Ameren Common Shareholders	—		52		—		52		—			—		—		52
Comprehensive Income Attributable to Ameren Common Shareholders	$	151	$	154	$	254	$	262	$	368		$	343	$	622	$	605

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

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

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


	June 30, 2016			December 31, 2015			September 30, 2016			December 31, 2015
ASSETS
Current Assets:
Cash and cash equivalents	$	13		$	292		$	18		$	292
Accounts receivable – trade (less allowance for doubtful accounts of $21 and $19, respectively)	445			388
Accounts receivable – trade (less allowance for doubtful accounts of $19 and $19, respectively)							543			388
Unbilled revenue	328			239			240			239
Miscellaneous accounts receivable	65			98			49			98
Materials and supplies	515			538			551			538
Current regulatory assets	146			260			107			260
Other current assets	68			88			76			88
Assets of discontinued operations	14			14			15			14
Total current assets	1,594			1,917			1,599			1,917
Property and Plant, Net	19,324			18,799			19,647			18,799
Investments and Other Assets:
Nuclear decommissioning trust fund	582			556			599			556
Goodwill	411			411			411			411
Regulatory assets	1,330			1,382			1,312			1,382
Other assets	552			575			566			575
Total investments and other assets	2,875			2,924			2,888			2,924
TOTAL ASSETS	$	23,793		$	23,640		$	24,134		$	23,640
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	431		$	395		$	431		$	395
Short-term debt	778			301			608			301
Accounts and wages payable	499			777			513			777
Taxes accrued	124			43			159			43
Interest accrued	102			89			110			89
Customer deposits	100			100			104			100
Current regulatory liabilities	99			80			87			80
Other current liabilities	270			279			252			279
Liabilities of discontinued operations	27			29			27			29
Total current liabilities	2,430			2,093			2,291			2,093
Long-term Debt, Net	6,605			6,880			6,607			6,880
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	4,028			3,885			4,255			3,885
Accumulated deferred investment tax credits	57			60			56			60
Regulatory liabilities	1,953			1,905			1,974			1,905
Asset retirement obligations	629			618			636			618
Pension and other postretirement benefits	537			580			499			580
Other deferred credits and liabilities	490			531			481			531
Total deferred credits and other liabilities	7,694			7,579			7,901			7,579
Commitments and Contingencies (Notes 2, 9, and 10)
Ameren Corporation Shareholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6	2			2			2			2
Other paid-in capital, principally premium on common stock	5,545			5,616			5,550			5,616
Retained earnings	1,376			1,331			1,643			1,331
Accumulated other comprehensive loss	(1		)	(3		)	(2		)	(3		)
Total Ameren Corporation shareholders’ equity	6,922			6,946			7,193			6,946
Noncontrolling Interests	142			142			142			142
Total equity	7,064			7,088			7,335			7,088
TOTAL LIABILITIES AND EQUITY	$	23,793		$	23,640		$	24,134		$	23,640

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

													AMEREN CORPORATION	CONSOLIDATED STATEMENT OF CASH FLOWS	(Unaudited) (In millions)
	Six Months Ended June 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Cash Flows From Operating Activities:
Net income	$	255		$	261		$	626		$	606
(Income) from discontinued operations, net of taxes	—			(52		)
Income from discontinued operations, net of taxes							—			(52		)
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for Callaway construction and operating license	—			69			—			69
Depreciation and amortization	419			387			625			582
Amortization of nuclear fuel	38			47			63			71
Amortization of debt issuance costs and premium/discounts	11			11			17			16
Deferred income taxes and investment tax credits, net	134			116			364			318
Allowance for equity funds used during construction	(13		)	(11		)	(20		)	(19		)
Share-based compensation costs	12			14			17			20
Other	(7		)	(13		)	(9		)	(8		)
Changes in assets and liabilities:
Receivables	(111		)	(80		)	(134		)	(71		)
Materials and supplies	23			25			(13		)	(23		)
Accounts and wages payable	(200		)	(180		)	(196		)	(172		)
Taxes accrued	80			83			119			116
Regulatory assets and liabilities	108			65			146			74
Assets, other	24			27			9			17
Liabilities, other	(12		)	(15		)	(29		)	(26		)
Pension and other postretirement benefits	4			28			(26		)	29
Net cash provided by operating activities – continuing operations	765			782			1,559			1,547
Net cash used in operating activities – discontinued operations	(2		)	(1		)	—			(5		)
Net cash provided by operating activities	763			781			1,559			1,542
Cash Flows From Investing Activities:
Capital expenditures	(1,000		)	(846		)	(1,496		)	(1,332		)
Nuclear fuel expenditures	(24		)	(28		)	(41		)	(30		)
Purchases of securities – nuclear decommissioning trust fund	(201		)	(117		)	(310		)	(301		)
Sales and maturities of securities – nuclear decommissioning trust fund	192			110			297			290
Proceeds from note receivable – Marketing Company	—			10			—			12
Contributions to note receivable – Marketing Company	—			(7		)	—			(8		)
Other	(2		)	3			(1		)	7
Net cash used in investing activities – continuing operations	(1,035		)	(875		)	(1,551		)	(1,362		)
Net cash used in investing activities – discontinued operations	—			—			—			—
Net cash used in investing activities	(1,035		)	(875		)	(1,551		)	(1,362		)
Cash Flows From Financing Activities:
Dividends on common stock	(206		)	(199		)	(309		)	(298		)
Dividends paid to noncontrolling interest holders	(3		)	(3		)	(5		)	(5		)
Short-term debt, net	477			172			307			69
Maturities of long-term debt	(389		)	(114		)	(389		)	(114		)
Issuances of long-term debt	149			249			149			249
Employee payroll taxes related to share-based payments	(32		)	(12		)
Employee withholding taxes related to share-based payments							(32		)	(12		)
Capital issuance costs	(1		)	(2		)	(1		)	(2		)
Other	(2		)	—			(2		)	—
Net cash provided by (used in) financing activities – continuing operations	(7		)	91
Net cash used in financing activities – continuing operations							(282		)	(113		)
Net change in cash and cash equivalents	(279		)	(3		)	(274		)	67
Cash and cash equivalents at beginning of year	292			5			292			5
Cash and cash equivalents at end of period	$	13		$	2		$	18		$	72

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

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

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015		2016		2015		2016		2015
Operating Revenues:
Electric	$	844	$	859	$	1,538	$	1,601	$	1,144	$	1,151	$	2,682	$	2,752
Gas	23		24		70		82		20		19		90		101
Other	—		1		—		1		1		1		1		2
Total operating revenues	867		884		1,608		1,684		1,165		1,171		2,773		2,855
Operating Expenses:
Fuel	166		205		369		411		205		259		574		670
Purchased power	50		19		92		58		77		29		169		87
Gas purchased for resale	6		7		27		38		6		5		33		43
Other operations and maintenance	238		229		450		440		220		233		670		673
Provision for Callaway construction and operating license (Note 2)	—		69		—		69		—		—		—		69
Depreciation and amortization	127		124		254		242		130		125		384		367
Taxes other than income taxes	83		85		156		165		96		97		252		262
Total operating expenses	670		738		1,348		1,423		734		748		2,082		2,171
Operating Income	197		146		260		261		431		423		691		684
Other Income and Expense:
Miscellaneous income	9		12		24		23		14		14		38		37
Miscellaneous expense	2		2		4		5		2		3		6		8
Total other income	7		10		20		18		12		11		32		29
Interest Charges	53		55		105		110		53		54		158		164
Income Before Income Taxes	151		101		175		169		390		380		565		549
Income Taxes	58		39		67		65		148		140		215		205
Net Income	93		62		108		104		242		240		350		344
Other Comprehensive Income	—		—		—		—		—		—		—		—
Comprehensive Income	$	93	$	62	$	108	$	104	$	242	$	240	$	350	$	344


Net Income	$	93	$	62	$	108	$	104	$	242	$	240	$	350	$	344
Preferred Stock Dividends	1		1		2		2		1		1		3		3
Net Income Available to Common Shareholder	$	92	$	61	$	106	$	102	$	241	$	239	$	347	$	341

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

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

BALANCE SHEET

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


	June 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	199	$	1	$	199
Advances to money pool	—		36		201		36
Accounts receivable – trade (less allowance for doubtful accounts of $7 and $7, respectively)	206		174		272		174
Accounts receivable – affiliates	15		54		20		54
Unbilled revenue	226		128		144		128
Miscellaneous accounts receivable	52		78		33		78
Materials and supplies	396		387		392		387
Current regulatory assets	46		89		47		89
Other current assets	33		41		37		41
Total current assets	974		1,186		1,147		1,186
Property and Plant, Net	11,242		11,183		11,294		11,183
Investments and Other Assets:
Nuclear decommissioning trust fund	582		556		599		556
Regulatory assets	536		605		514		605
Other assets	315		321		335		321
Total investments and other assets	1,433		1,482		1,448		1,482
TOTAL ASSETS	$	13,649	$	13,851	$	13,889	$	13,851
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	431	$	266	$	431	$	266
Short-term debt	77		—
Accounts and wages payable	204		417		209		417
Accounts payable – affiliates	40		56		89		56
Taxes accrued	113		31		149		31
Interest accrued	68		59		66		59
Current regulatory liabilities	21		28		11		28
Other current liabilities	139		120		116		120
Total current liabilities	1,093		977		1,071		977
Long-term Debt, Net	3,568		3,844		3,569		3,844
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	2,915		2,844		3,003		2,844
Accumulated deferred investment tax credits	55		58		54		58
Regulatory liabilities	1,197		1,172		1,211		1,172
Asset retirement obligations	623		612		630		612
Pension and other postretirement benefits	195		234		183		234
Other deferred credits and liabilities	24		28		21		28
Total deferred credits and other liabilities	5,009		4,948		5,102		4,948
Commitments and Contingencies (Notes 2, 8, 9, and 10)
Shareholders’ Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding	511		511		511		511
Other paid-in capital, principally premium on common stock	1,822		1,822		1,824		1,822
Preferred stock	80		80		80		80
Retained earnings	1,566		1,669		1,732		1,669
Total shareholders’ equity	3,979		4,082		4,147		4,082
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	13,649	$	13,851	$	13,889	$	13,851

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

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

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Six Months Ended June 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Cash Flows From Operating Activities:
Net income	$	108		$	104		$	350		$	344
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for Callaway construction and operating license	—			69			—			69
Depreciation and amortization	257			238			381			356
Amortization of nuclear fuel	38			47			63			71
Amortization of debt issuance costs and premium/discounts	3			3			5			5
Deferred income taxes and investment tax credits, net	66			27			159			88
Allowance for equity funds used during construction	(10		)	(9		)	(16		)	(16		)
Other							—			1
Changes in assets and liabilities:
Receivables	(103		)	(80		)	(95		)	(51		)
Materials and supplies	(9		)	(24		)	(5		)	(26		)
Accounts and wages payable	(174		)	(180		)	(176		)	(177		)
Taxes accrued	80			123			165			243
Regulatory assets and liabilities	55			63			60			101
Assets, other	14			16			(8		)	6
Liabilities, other	37			35			13			11
Pension and other postretirement benefits	2			14			(8		)	15
Net cash provided by operating activities	364			446			888			1,040
Cash Flows From Investing Activities:
Capital expenditures	(353		)	(289		)	(500		)	(444		)
Nuclear fuel expenditures	(24		)	(28		)	(41		)	(30		)
Purchases of securities – nuclear decommissioning trust fund	(201		)	(117		)	(310		)	(301		)
Sales and maturities of securities – nuclear decommissioning trust fund	192			110			297			290
Money pool advances, net	36			—			(165		)	(250		)
Other	(4		)	(4		)	(5		)	(4		)
Net cash used in investing activities	(354		)	(328		)	(724		)	(739		)
Cash Flows From Financing Activities:
Dividends on common stock	(210		)	(415		)	(285		)	(490		)
Dividends on preferred stock	(2		)	(2		)	(3		)	(3		)
Short-term debt, net	77			(59		)	—			(97		)
Maturities of long-term debt	(260		)	(114		)	(260		)	(114		)
Issuances of long-term debt	149			249			149			249
Capital contribution from parent	38			224			38			224
Capital issuance costs	(1		)	(2		)	(1		)	(2		)
Net cash used in financing activities	(209		)	(119		)	(362		)	(233		)
Net change in cash and cash equivalents	(199		)	(1		)	(198		)	68
Cash and cash equivalents at beginning of year	199			1			199			1
Cash and cash equivalents at end of period	$	—		$	—		$	1		$	69

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

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

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,					Nine Months Ended September 30,
	2016			2015			2016			2015			2016			2015		2016			2015
Operating Revenues:
Electric	$	411		$	386		$	803		$	776		$	562		$	540	$	1,365		$	1,316
Gas	131			127			416			482			114			115		530			597
Total operating revenues	542			513			1,219			1,258			676			655		1,895			1,913
Operating Expenses:
Purchased power	90			87			194			189			110			128		304			317
Gas purchased for resale	35			39			166			244			28			33		194			277
Other operations and maintenance	200			202			394			404			198			202		592			606
Depreciation and amortization	80			73			157			146			80			74		237			220
Taxes other than income taxes	30			29			68			72			30			29		98			101
Total operating expenses	435			430			979			1,055			446			466		1,425			1,521
Operating Income	107			83			240			203			230			189		470			392
Other Income and Expense:
Miscellaneous income	6			4			11			11			4			4		15			15
Miscellaneous expense	3			2			8			7			3			3		11			10
Total other income	3			2			3			4			1			1		4			5
Interest Charges	35			33			70			66			35			33		105			99
Income Before Income Taxes	75			52			173			141			196			157		369			298
Income Taxes	29			20			67			55			77			59		144			114
Net Income	46			32			106			86			119			98		225			184
Other Comprehensive Loss, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $-, $-, $(1) and $(1), respectively	(1		)	(1		)	(2		)	(2		)
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(1), $(1), $(2) and $(2), respectively													(1		)	—		(3		)	(2		)
Comprehensive Income	$	45		$	31		$	104		$	84		$	118		$	98	$	222		$	182


Net Income	$	46		$	32		$	106		$	86		$	119		$	98	$	225		$	184
Preferred Stock Dividends	1			1			2			2			—			—		2			2
Net Income Available to Common Shareholder	$	45		$	31		$	104		$	84		$	119		$	98	$	223		$	182

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

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

BALANCE SHEET

(Unaudited) (In millions)


	June 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	71	$	3	$	71
Accounts receivable – trade (less allowance for doubtful accounts of $14 and $12, respectively)	225		204
Accounts receivable – trade (less allowance for doubtful accounts of $12 and $12, respectively)					259		204
Accounts receivable – affiliates	15		22		13		22
Unbilled revenue	102		111		96		111
Miscellaneous accounts receivable	12		19		11		19
Materials and supplies	119		151		159		151
Current regulatory assets	98		167		59		167
Other current assets	11		15		17		15
Total current assets	582		760		617		760
Property and Plant, Net	7,121		6,848		7,285		6,848
Investments and Other Assets:
Goodwill	411		411		411		411
Regulatory assets	786		771		791		771
Other assets	99		113		98		113
Total investments and other assets	1,296		1,295		1,300		1,295
TOTAL ASSETS	$	8,999	$	8,903	$	9,202	$	8,903
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	—	$	129	$	—	$	129
Short-term debt	177		—		157		—
Borrowings from money pool					54		—
Accounts and wages payable	212		249		214		249
Accounts payable – affiliates	43		66		59		66
Taxes accrued	9		13		8		13
Interest accrued	29		28		40		28
Customer deposits	67		69		68		69
Mark-to-market derivative liabilities	23		45		21		45
Current environmental remediation	35		28		35		28
Current regulatory liabilities	59		39		56		39
Other current liabilities	88		86		99		86
Total current liabilities	742		752		811		752
Long-term Debt, Net	2,343		2,342		2,344		2,342
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,546		1,480		1,618		1,480
Accumulated deferred investment tax credits	2		2		2		2
Regulatory liabilities	754		732		761		732
Pension and other postretirement benefits	284		271		262		271
Environmental remediation	183		205		171		205
Other deferred credits and liabilities	207		222		212		222
Total deferred credits and other liabilities	2,976		2,912		3,026		2,912
Commitments and Contingencies (Notes 2, 8, and 9)
Shareholders’ Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding	—		—		—		—
Other paid-in capital	2,005		2,005		2,005		2,005
Preferred stock	62		62		62		62
Retained earnings	868		825		952		825
Accumulated other comprehensive income	3		5		2		5
Total shareholders’ equity	2,938		2,897		3,021		2,897
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	8,999	$	8,903	$	9,202	$	8,903

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

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

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Six Months Ended June 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Cash Flows From Operating Activities:
Net income	$	106		$	86		$	225		$	184
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	156			144			236			218
Amortization of debt issuance costs and premium/discounts	7			7			11			11
Deferred income taxes and investment tax credits, net	65			45			141			108
Other	(6		)	(5		)	(8		)	(7		)
Changes in assets and liabilities:
Receivables	(5		)	57			(36		)	45
Materials and supplies	32			48			(8		)	3
Accounts and wages payable	(20		)	20			(17		)	11
Taxes accrued	(14		)	(6		)	5			(10		)
Regulatory assets and liabilities	48			(1		)	75			(31		)
Assets, other	11			8			11			6
Liabilities, other	(1		)	(29		)	6			(10		)
Pension and other postretirement benefits	3			12			(14		)	13
Net cash provided by operating activities	382			386			627			541
Cash Flows From Investing Activities:
Capital expenditures	(442		)	(379		)	(683		)	(620		)
Other	4			4			4			5
Net cash used in investing activities	(438		)	(375		)	(679		)	(615		)
Cash Flows From Financing Activities:
Dividends on common stock	(60		)	—			(95		)	—
Dividends on preferred stock	(2		)	(2		)	(2		)	(2		)
Short-term debt, net	177			(20		)	157			(32		)
Money pool borrowings, net	—			10			54			107
Maturities of long-term debt	(129		)	—			(129		)	—
Other	(1		)	—			(1		)	—
Net cash used in financing activities	(15		)	(12		)
Net cash provided by (used in) financing activities							(16		)	73
Net change in cash and cash equivalents	(71		)	(1		)	(68		)	(1		)
Cash and cash equivalents at beginning of year	71			1			71			1
Cash and cash equivalents at end of period	$	—		$	—		$	3		$	—

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

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)

~~June~~September 30, 2016

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005. Ameren’s primary assets are its equity interests in its subsidiaries, including Ameren Missouri and Ameren Illinois. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.

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

Ameren Illinois Company, doing business as Ameren Illinois, operates rate-regulated electric and natural gas transmission and distribution businesses in Illinois.

Additionally, Ameren has a subsidiary, ATXI, that operates a FERC rate-regulated electric transmission business. ATXI is developing MISO-approved electric transmission projects, including the Illinois Rivers, Spoon River, and Mark Twain projects. Ameren is also pursuing projects to improve electric transmission system reliability within Ameren Missouri's and Ameren Illinois' service territories as well as evaluating competitive electric transmission investment opportunities outside of these territories, including investments outside of MISO.

Ameren also has various

other subsidiaries that conduct activities such as the provision of shared services.

Unless otherwise stated, these notes to Ameren’s financial statements exclude discontinued operations for all periods presented. See Note 12 – Discontinued Operations in this report and Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information.

Ameren’s financial statements are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All 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 statement 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.

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri, and Ameren Illinois increased during the ~~six~~nine months ended ~~June~~September 30, 2016, to reflect the accretion of ~~obligations~~the estimated obligation due to ~~their fair value,~~the passage of time, partially offset by immaterial settlements.

Share-based Compensation

A summary of nonvested performance share units at ~~June~~September 30, 2016, and changes during the ~~six~~nine months ended ~~June~~September 30, 2016, under the 2006 Incentive Plan and the 2014 Incentive Plan are presented below:


	Performance Share Units				Performance Share Units
	Share Units		Weighted-average Fair Value per Share Unit		Share Units		Weighted-average Fair Value per Share Unit
Nonvested at January 1, 2016	1,024,870		$	46.08	1,024,870		$	46.08
Granted^(a)	584,312		44.13		587,197		44.13
Forfeitures	(15,949	)	45.07		(15,949	)	45.07
Vested^(b)	(10,754	)	43.44		(23,114	)	44.41
Nonvested at June 30, 2016	1,582,479		$	45.39
Nonvested at September 30, 2016					1,573,004		$	45.39


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


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

The fair value of each performance share unit awarded in 2016 under the 2014 Incentive Plan was determined to be $44.13, which was based on Ameren’s closing common share price of $43.23 at December 31, 2015, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2016. The simulations can produce a greater fair value for the performance share unit than the December 31 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 1.31%, volatility of 15% to 20% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.

Excise Taxes

Ameren Missouri and Ameren Illinois collect certain excise taxes from customers that are levied on the sale or distribution of natural gas and electricity. Excise taxes are levied on Ameren Missouri’s electric and natural gas businesses and on Ameren Illinois’ natural gas business and 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 for electric service in Illinois are levied on the customer and are therefore not included in Ameren Illinois’ revenues and expenses. 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 ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Three Months				Six Months				Three Months				Nine Months
	2016		2015		2016		2015		2016		2015		2016		2015
Ameren Missouri	$	40	$	41	$	70	$	75	$	52	$	52	$	122	$	127
Ameren Illinois	11		10		31		33		9		9		40		42
Ameren	$	51	$	51	$	101	$	108	$	61	$	61	$	162	$	169

Earnings Per Share

Basic earnings per share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of common shares outstanding during the period. Earnings per diluted share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of diluted common shares outstanding during the period. Earnings per diluted share reflects the potential dilution that would occur if certain stock-based performance share units were settled. The number of performance share units assumed to be settled was 0.3 million and 0.4 million in the three and nine months ended September 30, 2016, respectively, and 1.3 million and 1.2 million, respectively, in the year-ago periods. There were no ~~material differences between Ameren’s basic and diluted~~potentially dilutive securities excluded from the earnings per diluted share ~~amounts~~calculations for the ~~six~~three and nine months ended ~~June~~September 30, 2016 and 2015. ~~The assumed settlement of dilutive performance share units had an immaterial impact on earnings per share.~~ The calculation of diluted earnings per share

prospectively reflected the adoption of FASB guidance related to employee share-based payment accounting discussed below.

Accounting and Reporting Developments

Below is a summary of recently issued authoritative accounting standards relevant to the Ameren Companies.

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative accounting guidance that changes the criteria for recognizing revenue from a

contract with a customer. The underlying principle of the guidance is that an entity will recognize revenue for the transfer of promised goods or services to customers at an amount that the entity expects to be entitled to 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. Entities can apply the guidance retrospectively to each reporting period presented or retrospectively by recording a cumulative effect adjustment to retained earnings in the period of initial adoption. The Ameren Companies are currently assessing the impact of this guidance on their results of operations, financial position, and disclosures, including their accounting for contributions in aid of construction and similar arrangements, as well as the transition method that they will use to adopt the guidance. The guidance will be effective for the Ameren Companies in the first quarter of 2018.

Amendments to the Consolidation Analysis

In February 2015, the FASB issued authoritative accounting guidance that amends the consolidation analysis for variable interest entities and voting interest entities. The new guidance affects (1) limited partnerships, similar legal entities, and certain investment funds, (2) the evaluation of fees paid to a decision maker or service provider as a variable interest, (3) how fee arrangements impact the primary beneficiary determination, and (4) the evaluation of related party relationships on the primary beneficiary determination. The adoption of this guidance in the first quarter of 2016 did not impact the Ameren Companies’ results of operations, financial position, liquidity, or disclosures.

Leases

In February 2016, the FASB issued authoritative accounting guidance that will require an entity to recognize assets and liabilities arising from a lease. Consistent with current GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease will depend primarily on its classification as a finance or operating lease. The guidance also requires additional disclosures to enable users of financial statements to understand the amount, timing, and uncertainty of cash flows arising from leases. The guidance will be effective for the Ameren Companies in the first quarter of 2019, with an option for entities to adopt early. Upon adoption, the Ameren Companies will recognize and measure operating leases on their respective balance sheets at the beginning of the earliest period presented. The Ameren Companies are currently assessing the impact of

this guidance on their results of operations, financial position, statement of cash flows, and disclosures.

Improvements to Employee Share-Based Payment Accounting

In March 2016, the FASB issued authoritative accounting guidance that simplifies the accounting for share-based payment transactions, including the income tax consequences, the calculation of diluted earnings per share, the treatment of forfeitures, the classification of awards as either equity or liabilities, and the classification on the statement of cash flows. Ameren determines for each performance share unit award

whether the difference between the deduction for tax purposes and the compensation cost recognized for financial reporting purposes results in either an excess tax benefit or an excess tax deficit. Previously, excess tax benefits were recognized in "Other paid-in capital" on Ameren’s consolidated balance sheet, and in certain cases, excess tax deficits were recognized in “Income taxes” on Ameren’s consolidated income statement. The new guidance increases income statement volatility by requiring all excess tax benefits and deficits to be recognized in “Income taxes,” and treated as discrete items in the period in which they occur. Ameren adopted this guidance in the first quarter of 2016 and prospectively applied the amendment in this guidance requiring recognition of excess tax benefits and deficits in the income statement, which resulted in recognition of a $21 million income tax benefit and a corresponding $21 million increase in income from continuing operations and net income (9 cents per diluted share) during ~~the~~that period. Also as a result of the adoption of this guidance, Ameren made an accounting policy election to continue to estimate the number of forfeitures expected to occur. The amendments in the guidance that require application using a modified retrospective transition method did not impact Ameren. Therefore, there was no cumulative-effect adjustment to retained earnings recognized as of January 1, 2016. Ameren applied the amendments in this guidance relating to classification on the statement of cash flows retrospectively. As a result, for the ~~six~~nine months ended ~~June~~September 30, 2015, Ameren reclassified, for comparison purposes, $2 million of excess tax benefits on the statement of cash flows from financing to operating activity, and $12 million of employee payroll taxes related to share-based payments from operating to financing activity.

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

2016 Electric Rate Case

On July 1, 2016, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $206 million. The electric rate increase request

is based on a 9.9% return on equity, a capital structure ~~composed~~comprised of 51.8% equity, a rate base of $7.2 billion, and a test year ended March 31, 2016, with certain pro-forma adjustments ~~expected~~ through the ~~anticipated~~ true-up date of December 31, 2016. The rate request includes $74 million that is primarily ~~related~~relates to nearly $1.4 billion of new gross electric infrastructure investments ~~that have been placed into service~~ since the true-up date in Ameren Missouri’s last electric rate case. This $74 million includes depreciation expenses of $39 million, return on rate base of $25 million, and increased property taxes of $10 million. The rate request also includes $51 million related to reduced customer

sales volumes, including reductions from the ~~idling of~~suspended operations at ~~Noranda’s aluminum smelter,~~the New Madrid Smelter, and $34 million related to increases in transmission charges. Other changes in expenses reflected in the rate request include decreases in pension and other post-employment benefit plan expenses of $24 million and solar rebate expenses of $15 million, both of which are subject to regulatory tracking mechanisms; increased net energy costs, excluding the impact of ~~reduced Noranda~~the suspended operations at the New Madrid Smelter and other customer sales volumes, of $23 million; and increased income taxes of $15 million.

As a part of its filing, Ameren Missouri requested the amortization over ten years of an estimated $81 million of lost fixed cost recovery due to lower sales volumes, as discussed below, from ~~Noranda~~the New Madrid Smelter during the period April 2015 through May 2017.

Ameren Missouri also requested continued use of its FAC and the regulatory tracking mechanisms for pension and postretirement benefits and uncertain income tax positions that the MoPSC previously authorized in earlier electric rate orders. Additionally, Ameren Missouri requested the implementation of a new regulatory tracking mechanism for transmission charges and revenues.

The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by late April 2017 and new rates effective in late May 2017. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, whether the requested regulatory tracking mechanisms will be approved, 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.

Noranda and New Madrid Smelter

In the first quarter of 2016, Noranda ~~idled production~~suspended operations at ~~its aluminum smelter~~the New Madrid Smelter and filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. In October 2016, Noranda sold the New Madrid Smelter to ARG International AG. As of ~~June~~September 30, 2016, Ameren Missouri has been paid in full for all previous electric service amounts, and expects to continue to be paid in full for ~~its~~the minimal amount of electric service ~~provided~~it is currently providing to ~~Noranda.~~the New Madrid Smelter.

In its April 2015 electric rate order, the MoPSC approved a rate design that established $78 million in annual revenues, net of fuel and purchased power costs, as ~~Noranda’s~~the New Madrid Smelter’s portion of Ameren Missouri’s revenue requirement. ~~The portion~~In 2016, as a result of ~~Ameren Missouri’s annual revenue requirement reflected in Noranda’s electric rate is based on~~ the smelter using approximately 4.2 million megawatthours annually, which is almost 100% of its operating capacity. Ameren Missouri’s rates, including those for Noranda, are seasonal. Noranda’s summer base rate (June through September) is $45.78 per megawatthour, and its winter base rate (October through May) is $31.11 per megawatthour.

~~In 2016,~~suspended operations, actual sales volumes to ~~Noranda will be~~the New Madrid Smelter are significantly below the sales volumes reflected in rates. As a

result, full recovery by Ameren Missouri of its revenue requirement has not occurred and will not occur until rates are adjusted prospectively by the MoPSC in the July 2016 electric rate case to accurately reflect ~~Noranda’s~~the actual sales ~~volumes.~~volumes to the New Madrid Smelter. In its July 2016 electric rate case, Ameren Missouri is seeking to recover the April 2015 through May 2017 lost fixed costs caused by the lower ~~Noranda~~ sales volumes ~~in its July 2016 electric rate case.~~to New Madrid Smelter. Also, as a result of ~~Noranda’s idled production described above,~~the New Madrid Smelter’s suspended operations, Ameren Missouri is applying a provision in its FAC tariff that, under certain circumstances, allows Ameren Missouri to retain a portion of the revenues from any off-system sales it makes as a result of reduced ~~tariff~~ sales to ~~Noranda.~~the smelter. The current market price of electricity is less than ~~Noranda’s~~the New Madrid Smelter’s electric rate, and Ameren Missouri expects market prices to remain below ~~Noranda’s~~the New Madrid Smelter’s electric rate ~~during 2016.~~through the date that new rates in the July 2016 rate case become effective. Accordingly, this FAC-tariff provision will not enable Ameren Missouri to fully recover its revenue requirement under current market conditions. Operations at the New Madrid Smelter remain suspended and Ameren Missouri is uncertain of future sales to the smelter.

MEEIA 2013

The MEEIA 2013 performance incentive allowed Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy efficiency goals, including $19 million if 100% of the goals were achieved during the three-year period, with the potential to earn a larger performance incentive if Ameren Missouri’s energy savings exceeded those goals. In September 2016, Ameren Missouri ~~has not recorded any revenues associated~~and the MoPSC staff filed a stipulation agreement with the MoPSC that supported a $29 million MEEIA 2013 performance incentive. The MoOPC opposed this stipulation agreement; however, it did not oppose the conclusion that Ameren Missouri ~~believes it will ultimately be found to have exceeded~~achieved at least 100% of the customer energy efficiency goals. ~~Therefore, regardless~~As there was no challenge to the achievement of at least 100% of the ~~outcome of the appeal discussed below,~~customer energy efficiency goals, Ameren Missouri ~~expects~~recognized $19 million of revenue during the third quarter of 2016 related to the MEEIA 2013 performance incentive. In November 2016, the MoPSC approved a $28 million MEEIA 2013 performance incentive based on a revised stipulation agreement between Ameren Missouri, the MoPSC staff, and the MoOPC. As a result, Ameren Missouri will recognize $9 million of additional revenues in the fourth quarter of 2016 relating to the MEEIA 2013 performance ~~incentive~~incentive. Further, the revised stipulation agreement included a provision to incorporate the results of ~~at least $19 million in 2016.~~the appeal, discussed below, regarding the determination of an input used to calculate the performance incentive.

In November 2015, the MoPSC issued an order ~~that clarified~~regarding the ~~method applied to determine~~determination of an input used to calculate the performance incentive. Ameren Missouri filed an appeal of the order with the

Missouri Court of Appeals, Western District, which is expected to issue a decision in 2016. If the Missouri Court of Appeals, Western District, overturns the ~~MoPSC’s~~ November 2015 MoPSC order, Ameren Missouri may recognize additional revenues in excess of the ~~MEEIA 2013 performance incentive will be more than~~$28 million approved by the ~~performance incentive calculated using the MoPSC’s~~MoPSC in November ~~2015 order.~~

2016.

ATXI’s Mark Twain Project

~~ATXI Transmission Projects~~

The Mark Twain project is a MISO-approved 95-mile transmission line to be located in northeast Missouri. In April 2016, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. ~~Starting~~Before starting construction, ~~under the certificate is subject to~~ ATXI ~~obtaining~~must obtain assents for road crossings from the five counties where the line will be constructed. ~~The Mark Twain project~~None of the five county commissions approved ATXI’s requests for the assents. In October 2016, ATXI filed suit in each of the five county circuit courts to obtain the assents. A decision from each of the county circuit courts is expected in 2017. ATXI plans to ~~be completed~~complete the project in ~~2018. Extended difficulties~~2018; however, delays in obtaining the assents could delay the completion date. ~~ATXI is in the process of obtaining the assents.~~

Illinois

IEIMA

Under the provisions of the IEIMA's performance-based formula rate-making framework, which currently extends through 2019, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable 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 reflected in customer rates 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 recoverable costs incurred. As of ~~June~~September 30, 2016, Ameren Illinois had recorded regulatory assets of ~~$12~~$23 million, $66 million, and ~~$58~~$22 million to reflect its expected 2016 and 2015 revenue requirement reconciliation adjustments, and the approved 2014 revenue requirement reconciliation adjustment, with interest, respectively.

In April 2016, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for 2017 rates. Pending ICC approval, ~~and if approved as filed,~~ Ameren Illinois’ update filing ~~would~~will result in a $14 million decrease in Ameren Illinois’ electric distribution service revenue requirement, beginning in January 2017. This update reflects an increase to the annual formula rate based on 2015 actual costs and expected net plant additions for 2016, an increase to include the 2015 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the 2014 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2016, consistent with the ICC’s December 2015 annual update filing order. As of December 31, 2015, Ameren Illinois had recorded a regulatory asset of $103 million related to the approved 2014 revenue requirement reconciliation adjustment. In ~~July~~October 2016, ~~the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing. The ICC staff recommended~~an administrative law judge issued a proposed order that reflected a decrease ~~in the~~ to Ameren Illinois’

electric distribution service revenue requirement in an amount consistent with Ameren Illinois’ filing. Other intervenors to this rate proceeding have recommended additional decreases to Ameren Illinois’ electric distribution service revenue requirement.of $14 million. An ICC decision on the revenue requirement used for 2017 rates is expected by December 2016.

Federal

FERC Complaint Cases

In November 2013, a customer group filed a complaint case with the FERC seeking a reduction in the allowed base return on common equity for the FERC-regulated transmission rate base under the MISO tariff from 12.38% to 9.15%. In ~~December 2015, an administrative law judge~~September 2016, the FERC issued ~~an initial decision~~a final order in the November 2013 complaint case ~~that would lower~~which lowered the allowed base return on common equity to 10.32%. The order was consistent with the initial decision an administrative law judge issued in December 2015 and ~~would require~~requires customer refunds, with interest, to be issued for the 15-month period ~~ending~~ended February 2015. ~~The FERC is expected to issue a final order in~~In addition, the ~~November 2013 complaint case in the fourth quarter of 2016, which will determine the~~new allowed base return on common equity ~~for~~is reflected in rates prospectively from the ~~15-month period ending February 2015. The final order in~~September 2016 effective date of the order. Refunds for the November 2013 complaint case ~~will also establish a new allowed base return on equity that will replace~~are expected to be issued in the ~~current allowed base return on common equity~~first half of 12.38% for the period between the effective date of the November 2013 complaint case order and the effective date of the allowed base return on common equity established by the February 2015 complaint case, as discussed below.2017.

After the maximum FERC-allowed refund period for the November 2013 complaint case ended in February 2015, another customer complaint case was filed in February 2015. The February 2015 complaint case seeks a reduction in the allowed base return on common equity for the FERC-regulated transmission rate base under the MISO tariff to 8.67%. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case ~~that~~which would lower the allowed base return on common equity to 9.70% and would require customer refunds, with interest, to be issued for the 15-month period ~~ending~~ended May 2016. The FERC is expected to issue a final order in the February 2015 complaint case in the second quarter of ~~2017, which~~2017. The final order in the February 2015 complaint case will determine the allowed base return on common equity for the 15-month period ~~ending~~ended May 2016. The final order in the February 2015 complaint case will also establish the allowed base return on common equity that will apply prospectively from ~~the~~its expected second quarter 2017 effective date, replacing the 10.32% allowed base return on common equity, which became effective in September 2016. The 12.38% allowed base return on common equity was effective for the period that began at the conclusion of the 15-month period for the February 2015 complaint case in May

2016 through the September 2016 effective date of the final order ~~replacing the allowed base return on equity established by~~in the November 2013 complaint case.

On January 6, 2015, a FERC-approved incentive adder of up to 50 basis points on the allowed base return on common equity for our participation in an RTO became effective. Beginning with its January 6, 2015 effective date, the incentive adder ~~will reduce~~reduces any refund to customers relating to a reduction of the allowed base return on common equity from the complaint cases discussed ~~above.~~above and will also be applied prospectively from the effective date of the September 2016 FERC order, resulting in a current allowed return on common equity of 10.82%.

As of ~~June~~September 30, 2016, Ameren and Ameren Illinois recorded current regulatory liabilities of ~~$58~~$61 million and ~~$39~~$42 million, respectively, to reflect the ~~potential~~expected refunds, including interest, associated with the reduced allowed base returns on common equity in the September 2016 FERC order and the initial ~~decisions for~~decision in the ~~November 2013 and~~ February 2015 complaint ~~cases. Ameren’s and Ameren Illinois’ liabilities also reflect the January 6, 2015 incentive adder discussed above.~~case. Ameren Missouri did not record a liability as of ~~June~~September 30, 2016, ~~and~~as it does 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.

Combined Construction and Operating License

In 2008, Ameren Missouri filed an application with the NRC for a COL for a second nuclear unit at Ameren Missouri's existing Callaway County, Missouri, energy center site. In 2009, Ameren Missouri suspended its efforts to build a second nuclear unit at its existing Callaway site, and the NRC suspended review of the COL application. Prior to suspending its efforts, Ameren Missouri had capitalized $69 million related to the project. Primarily because of changes in vendor support for licensing efforts at the NRC, Ameren Missouri’s assessment of long-term capacity needs, declining costs of alternative generation technologies, and the regulatory framework in Missouri, Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway site. As a result of this decision, in the second quarter of 2015, Ameren and Ameren Missouri recognized a $69 million noncash pretax provision for all of the previously capitalized COL costs. Ameren Missouri has withdrawn its COL application with the NRC.

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 Missouri Credit Agreement and the Illinois Credit Agreement, both of which expire on December 11, 2019, were not utilized for direct borrowings during the ~~six~~nine months ended ~~June~~September 30, 2016, but were used to support commercial paper issuances and to issue letters of credit. Based on commercial paper outstanding, as well as letters of credit issued under the Credit Agreements, ~~as well as commercial paper outstanding,~~ the aggregate amount of credit capacity available under the Credit Agreements to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, at ~~June~~September 30, 2016, was $~~1.3~~1.5 billion.

Commercial Paper

The following table presents commercial paper outstanding as of ~~June~~September 30, 2016, and December 31, 2015:


	June 30, 2016		December 31, 2015		2016		2015
Ameren (parent)	$	524	$	301	$	451	$	301
Ameren Missouri	77		—		—		—
Ameren Illinois	177		—		157		—
Ameren Consolidated	$	778	$	301	$	608	$	301

The following table summarizes the borrowing activity and relevant interest rates under Ameren’s (parent), Ameren Missouri’s, and Ameren Illinois’ commercial paper programs for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated			Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated
2016
Average daily commercial paper outstanding	$	402		$	117		$	12		$	531		$	435		$	80		$	48		$	563
Weighted-average interest rate	0.82		%	0.74		%	0.79		%	0.80		%	0.81		%	0.74		%	0.72		%	0.79		%
Peak commercial paper during period^(a)	$	549		$	208		$	177		$	839		$	574		$	208		$	195		$	839
Peak interest rate	0.95		%	0.85		%	0.85		%	0.95		%	0.95		%	0.85		%	0.85		%	0.95		%
2015
Average daily commercial paper outstanding	$	754		$	84		$	5		$	843		$	770		$	56		$	6		$	832
Weighted-average interest rate	0.57		%	0.50		%	0.44		%	0.56		%	0.56		%	0.50		%	0.44		%	0.56		%
Peak commercial paper during period^(a)	$	849		$	294		$	39		$	1,108		$	874		$	294		$	48		$	1,108
Peak interest rate	0.70		%	0.60		%	0.60		%	0.70		%	0.70		%	0.60		%	0.60		%	0.70		%


(a)	The timing of peak commercial paper issuances varies by company; 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 financial covenants in the 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 Credit Agreements also contain nonfinancial covenants, including restrictions on the ability to incur liens, to transact with affiliates, to dispose of assets, to make investments in or transfer assets to its affiliates, and to merge with other entities.

The Credit Agreements require Ameren, Ameren Missouri, and Ameren Illinois to each 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 ~~June~~September 30, 2016, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the provisions of the Credit Agreements, were ~~52%~~51%, ~~49%~~48%, and ~~47%~~46% for Ameren, Ameren Missouri, and Ameren Illinois, respectively. In addition, under the Credit Agreements, if Ameren does not have a senior long-term unsecured credit rating of at least Baa3 from Moody’s or BBB- from S&P, 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. As of ~~June~~September 30, 2016, Ameren’s senior long-term unsecured credit rating exceeded the minimum rating requirements; therefore, the interest coverage requirement was not applicable. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable Credit Agreement.

The Credit Agreements contain default provisions that apply

separately to each borrower; provided, however, that a default of Ameren Missouri or Ameren Illinois under the applicable Credit Agreement will also be deemed to constitute a default of Ameren under such agreement. Defaults include a cross-default resulting from a default of such borrower under any other agreement covering outstanding indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and nonmaterial subsidiaries) in excess of $75 million in the aggregate (including under the other Credit Agreement). However, under the default provisions of the Credit Agreements, any default of Ameren under any Credit Agreement that results solely from a default of Ameren Missouri or Ameren Illinois thereunder does not result in a cross-default of Ameren under the other Credit Agreement. Further, the Credit Agreement default provisions provide that an Ameren default under any of the Credit Agreements does not constitute a default by Ameren Missouri or Ameren Illinois.

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 covenants in their credit agreements at ~~June~~September 30, 2016.

Money Pools

Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements.

Ameren Missouri, Ameren Illinois, and ATXI may participate in the utility money pool as both lenders and borrowers. Ameren

(parent) and Ameren Services may participate in the utility money pool only as lenders. 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 Credit Agreements and the commercial paper programs. The total amount available to the money 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 money pool participants advance surplus funds to the

utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. Participants receiving a loan under the

utility money pool 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 ~~six~~nine months ended ~~June~~September 30, 2016, was ~~0.60%~~0.53% and 0.54%, respectively (2015 ~~- 0.08% for both periods)~~– 0.10% and 0.09%, 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 ~~six~~nine months ended ~~June~~September 30, 2016 and 2015.

NOTE 4 – LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren Missouri

In February 2016, Ameren Missouri's $260 million of 5.40% senior secured notes matured and were repaid with cash on hand and commercial paper borrowings.

In June 2016, Ameren Missouri issued $150 million of 3.65% senior secured notes due April 15, 2045, with interest payable semiannually on April 15 and October 15 of each year, beginning October 15, 2016. Ameren Missouri received proceeds of $148 million, which were used to repay ~~short-term debt.~~commercial paper borrowings.

Ameren Illinois

In June 2016, Ameren Illinois’ $54 million of 6.20% senior secured notes and $75 million of 6.25% senior secured notes matured and were repaid with commercial paper borrowings.

Indenture Provisions and Other Covenants

Ameren Missouri’s and Ameren Illinois’ indentures, credit facilities, 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 first mortgage bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges, dividend coverage ratios, and first mortgage bonds and preferred stock issuable as of ~~June~~September 30, 2016, 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		Required Interest Coverage Ratio^(a)	Actual Interest Coverage Ratio		Bonds Issuable^(b)		Required Dividend Coverage Ratio^(c)	Actual Dividend Coverage Ratio		Preferred Stock Issuable
Ameren Missouri	≥2.0	4.7	$	3,793		≥2.5	105.4	$	2,346		≥2.0	4.7	$	3,838		≥2.5	105.9	$	2,357
Ameren Illinois	≥2.0	6.9		3,827	^(d)	≥1.5	2.8		203	^(e)	≥2.0	7.3		3,942	^(d)	≥1.5	3.0		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 first mortgage bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include first mortgage bonds issuable based on retired bond capacity of $1,206 million and $279 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 first mortgage bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture. The amount of first mortgage bonds issuable by Ameren Illinois is also subject to the lien restrictions contained in the Illinois Credit Agreement.


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

Ameren's indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the

acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including borrowings under the Credit Agreements or the Ameren commercial paper program, constitutes a default

under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a ~~specified period.~~

specified period.

Ameren Missouri and Ameren Illinois and certain other Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The 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 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 the FERC to maintain a minimum of 30% equity in its capital structure. As of ~~June~~September 30, 2016, Ameren Illinois had 51% equity in its capital structure.

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

Off-Balance-Sheet Arrangements

At ~~June~~September 30, 2016, none of the Ameren Companies had off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business, letters of credit, and Ameren parent guarantee arrangements on behalf of its subsidiaries. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

NOTE 5 – OTHER INCOME AND EXPENSES

The following table presents the components of “Other Income and Expenses” in the Ameren Companies’ statements of income for the ~~six~~three and nine months ended ~~June~~September 30, 2016 and 2015:


	Three Months				Six Months				Three Months				Nine Months
	2016		2015		2016		2015		2016		2015		2016		2015
Ameren:^(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	5	$	6	$	13	$	11	$	7	$	8	$	20	$	19
Interest income on industrial development revenue bonds	6		6		13		13		7		7		20		20
Interest income	4		4		8		8		3		4		11		12
Other	1		—		2		3		1		—		3		3
Total miscellaneous income	$	16	$	16	$	36	$	35	$	18	$	19	$	54	$	54
Miscellaneous expense:
Donations	$	2	$	2	$	7	$	10	$	1	$	—	$	8	$	10
Other	4		4		6		7		7		5		13		12
Total miscellaneous expense	$	6	$	6	$	13	$	17	$	8	$	5	$	21	$	22
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	3	$	5	$	10	$	9	$	6	$	7	$	16	$	16
Interest income on industrial development revenue bonds	6		6		13		13		7		7		20		20
Interest income	—		1		—		1		1		—		1		1
Other	—		—		1		—		—		—		1		—
Total miscellaneous income	$	9	$	12	$	24	$	23	$	14	$	14	$	38	$	37
Miscellaneous expense:
Donations	$	1	$	1	$	2	$	3	$	—	$	—	$	2	$	3
Other	1		1		2		2		2		3		4		5
Total miscellaneous expense	$	2	$	2	$	4	$	5	$	2	$	3	$	6	$	8


	Three Months				Six Months				Three Months				Nine Months
	2016		2015		2016		2015		2016		2015		2016		2015
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	2	$	1	$	3	$	2	$	1	$	1	$	4	$	3
Interest income	3		3		7		7		2		3		9		10
Other	1		—		1		2		1		—		2		2
Total miscellaneous income	$	6	$	4	$	11	$	11	$	4	$	4	$	15	$	15
Miscellaneous expense:
Donations	$	1	$	1	$	5	$	4	$	1	$	—	$	6	$	4
Other	2		1		3		3		2		3		5		6
Total miscellaneous expense	$	3	$	2	$	8	$	7	$	3	$	3	$	11	$	10


(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, power, and uranium, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. Such price fluctuations may cause the following:

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

market values of natural gas and uranium inventories that differ from the cost of those commodities in inventory; and

actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.

The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.

The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of ~~June~~September 30, 2016, and December 31, 2015. As of ~~June~~September 30, 2016, these contracts extended through October 2018, March 2021, May 2032, and ~~January 2019~~February 2020 for fuel oils, natural gas, power, and uranium, respectively.


	Quantity (in millions, except as indicated)						Quantity (in millions, except as indicated)
	2016			2015			2016			2015
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)^(a)	24	(b)	24	35	(b)	35	25	(b)	25	35	(b)	35
Natural gas (in mmbtu)	30	131	161	30	151	181	26	128	154	30	151	181
Power (in megawatthours)	1	10	11	1	10	11	1	9	10	1	10	11
Uranium (pounds in thousands)	395	(b)	395	494	(b)	494	445	(b)	445	494	(b)	494


(a)	Consists of ultra-low-sulfur diesel products.


(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 whether the resulting gains or losses 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 liabilities in the period in which the change occurs. We believe derivative losses and gains deferred as regulatory assets and liabilities are probable of recovery, or refund, through future rates charged to customers. Regulatory assets and 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 ~~June~~September 30, 2016, and December 31, 2015, all contracts that met the definition of a derivative and are not eligible for the NPNS exception 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 a master netting arrangement or similar agreement. The Ameren

Companies did not elect to adopt this guidance for any eligible derivative instruments.

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 ~~June~~September 30, 2016,, and December 31, ~~2015~~:2015:


	Balance Sheet Location	Ameren Missouri		Ameren Illinois		Ameren		Balance Sheet Location	Ameren Missouri		Ameren Illinois		Ameren
2016	2016							2016
Fuel oils								Other assets	$	1	$	—	$	1
Natural gas	Other current assets	$	—	$	2	$	2	Other current assets	—		2		2
	Other assets	1		3		4		Other assets	—		1		1
Power	Other current assets	15		—		15		Other current assets	11		—		11
	Total assets ^(a)	$	16	$	5	$	21	Total assets ^(a)	$	12	$	3	$	15
Fuel oils	Other current liabilities	$	12	$	—	$	12	Other current liabilities	$	8	$	—	$	8
	Other deferred credits and liabilities	2		—		2		Other deferred credits and liabilities	1		—		1
Natural gas	MTM derivative liabilities	(b)		11		(b)		MTM derivative liabilities	(b)		9		(b)
	Other current liabilities	3		—		14		Other current liabilities	3		—		12
	Other deferred credits and liabilities	6		6		12		Other deferred credits and liabilities	6		9		15
Power	MTM derivative liabilities	(b)		12		(b)		MTM derivative liabilities	(b)		12		(b)
	Other current liabilities	1		—		13		Other current liabilities	2		—		14
	Other deferred credits and liabilities	—		157		157		Other deferred credits and liabilities	—		160		160
Uranium	Other current liabilities	1		—		1		Other current liabilities	2		—		2
	Other deferred credits and liabilities	3		—		3		Other deferred credits and liabilities	3		—		3
	Total liabilities ^(c)	$	28	$	186	$	214	Total liabilities ^(c)	$	25	$	190	$	215
2015	2015							2015
Natural gas	Other current assets	$	—	$	1	$	1	Other current assets	$	—	$	1	$	1
	Other assets	1		—		1		Other assets	1		—		1
Power	Other current assets	16		—		16		Other current assets	16		—		16
	Total assets ^(a)	$	17	$	1	$	18	Total assets ^(a)	$	17	$	1	$	18
Fuel oils	Other current liabilities	$	22	$	—	$	22	Other current liabilities	$	22	$	—	$	22
	Other deferred credits and liabilities	7		—		7		Other deferred credits and liabilities	7		—		7
Natural gas	MTM derivative liabilities	(b)		32		(b)		MTM derivative liabilities	(b)		32		(b)
	Other current liabilities	6		—		38		Other current liabilities	6		—		38
	Other deferred credits and liabilities	8		18		26		Other deferred credits and liabilities	8		18		26
Power	MTM derivative liabilities	(b)		13		(b)		MTM derivative liabilities	(b)		13		(b)
	Other current liabilities	—		—		13		Other current liabilities	—		—		13
	Other deferred credits and liabilities	—		157		157		Other deferred credits and liabilities	—		157		157
Uranium	Other current liabilities	1		—		1		Other current liabilities	1		—		1
	Total liabilities ^(c)	$	44	$	220	$	264	Total liabilities ^(c)	$	44	$	220	$	264


(a)	~~Because all contracts qualifying for hedge accounting receive regulatory deferral, the~~The cumulative amount of pretax net gains on all derivative instruments is deferred as a regulatory liability.


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


(c)	~~Because all contracts qualifying for hedge accounting receive regulatory deferral, the~~The cumulative amount of pretax net losses on all derivative instruments is deferred as a regulatory asset.

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 netting arrangements or similar agreements, and reporting daily exposure to senior management.

We believe that entering into master netting arrangements or similar agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. These master netting arrangements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at the master netting arrangement or similar 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 ~~June~~September 30, 2016, and December 31, 2015:


			Gross Amounts Not Offset in the Balance Sheet								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		Gross Amounts Recognized in the Balance Sheet		Derivative Instruments		Cash Collateral Received/Posted^(a)		Net Amount
2016
Assets:
Ameren Missouri	$	16	$	2	$	—	$	14	$	12	$	2	$	—	$	10
Ameren Illinois	5		4		—		1		3		2		—		1
Ameren	$	21	$	6	$	—	$	15	$	15	$	4	$	—	$	11
Liabilities:
Ameren Missouri	$	28	$	2	$	4	$	22	$	25	$	2	$	5	$	18
Ameren Illinois	186		4		—		182		190		2		—		188
Ameren	$	214	$	6	$	4	$	204	$	215	$	4	$	5	$	206
2015
Assets:
Ameren Missouri	$	17	$	1	$	—	$	16	$	17	$	1	$	—	$	16
Ameren Illinois	1		—		—		1		1		—		—		1
Ameren	$	18	$	1	$	—	$	17	$	18	$	1	$	—	$	17
Liabilities:
Ameren Missouri	$	44	$	1	$	8	$	35	$	44	$	1	$	8	$	35
Ameren Illinois	220		—		3		217		220		—		3		217
Ameren	$	264	$	1	$	11	$	252	$	264	$	1	$	11	$	252


(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 NPNS and other accrual contracts. These exposures are calculated on a gross basis, which include affiliate exposure not eliminated at the consolidated Ameren level. The potential loss on counterparty exposures may be reduced or eliminated by the application of master netting arrangements or similar agreements and collateral held. As of ~~June~~September 30, 2016, if counterparty groups were to fail completely to perform on contracts, the Ameren Companies’ maximum exposure would have been immaterial with or without consideration of the application of master netting arrangements or similar agreements and collateral held.

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 were downgraded, or if a counterparty with reasonable grounds for uncertainty regarding our ability to satisfy an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of ~~June~~September 30, 2016, 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 counterparties could require. The additional collateral required is the net liability position allowed under the master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered on ~~June~~September 30, 2016, 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)		Aggregate Fair Value of Derivative Liabilities^(a)		Cash Collateral Posted		Potential Aggregate Amount of Additional Collateral Required^(b)
2016
Ameren Missouri	$	74	$	2	$	66	$	69	$	2	$	60
Ameren Illinois	50		—		41		53		—		46
Ameren	$	124	$	2	$	107	$	122	$	2	$	106


(a)	Before consideration of master netting arrangements or similar agreements and including NPNS and other accrual contract exposures.


(b)	As collateral requirements with certain counterparties are based on master netting arrangements or similar agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such arrangements.

NOTE 7 – FAIR VALUE MEASUREMENTS

Fair value is defined as the 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 three hierarchy levels. See

Note 8 – Fair Value Measurements under Part II, Item 8, of the Form 10-K for information related to hierarchy levels. We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

The following table describes the valuation techniques and unobservable inputs utilized by the Ameren Companies for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the periods ended ~~June~~September 30, 2016, and December 31, 2015:

Fair Value

Weighted Average

Fair Value

Weighted Average

Assets

Liabilities

Valuation Technique(s)

Unobservable Input

Range

Assets

Liabilities

Valuation Technique(s)

Unobservable Input

Range

Level 3 Derivative asset and liability – commodity contracts^(a):

2016

Natural gas

—

)

Discounted cash flow

Nodal basis ($/mmbtu)^(b)

(0.80) – 0

(0.50)

Fuel oils

—

Option model

Volatilities(%)^(b)

25 – 38

Counterparty credit risk (%)^(c)(d)

0.22 – 6

Discounted cash flow

Counterparty credit risk(%)^(c)(d)

0.22

(e)

Ameren Illinois credit risk (%)^(c)(d)

0.38

(e)

Ameren Missouri credit risk(%)^(c)(d)

0.38

(d)

Power^(f)

(170

)

Discounted cash flow

Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(g)

27 – 43

Power^(f)

(174

)

Discounted cash flow

Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(g)

25 – 42

Estimated auction price for FTRs ($/MW)^(b)

(309) – 1,509

Estimated auction price for FTRs ($/MW)^(b)

(253) – 3,593

Nodal basis ($/MWh)^(g)

(9) – (1)

(2)

Nodal basis ($/MWh)^(g)

(6) – 0

(2)

Counterparty credit risk (%)^(c)(d)

0.56

(e)

Ameren credit risk (%)^(c)(d)

0.38

(e)

Ameren Illinois credit risk (%)^(c)(d)

0.38

(e)

Fundamental energy production model

Estimated future gas prices ($/mmbtu)^(b)

3 – 5

Fundamental energy production model

Estimated future gas prices ($/mmbtu)^(b)

3 – 5

Escalation rate (%)^(b)(h)

(e)

Escalation rate (%)^(b)(h)

(e)

Contract price allocation

Estimated renewable energy credit costs ($/credit)^(b)

5 – 7

Contract price allocation

Estimated renewable energy credit costs ($/credit)^(b)

5 – 7

Uranium

—

)

Option model

Volatilities (%)^(b)

(e)

Uranium

—

)

Option model

Volatilities (%)^(b)

(e)

Discounted cash flow

Average forward uranium pricing ($/pound)^(b)

22 – 26

Discounted cash flow

Average forward uranium pricing ($/pound)^(b)

27 – 30

Ameren Missouri credit risk (%)^(c)(d)

0.38

(e)

Ameren Missouri credit risk (%)^(c)(d)

0.38

(e)

2015

Natural gas

)

Option model

Volatilities (%)^(b)

35 – 55

Nodal basis ($/mmbtu)^(c)

(0.30) – 0

(0.20)

Discounted cash flow

Nodal basis ($/mmbtu)^(b)

(0.10) – 0

(0.10)

Counterparty credit risk (%)^(c)(d)

0.40 – 12

Ameren Missouri credit risk (%)^(c)(d)

0.40

(e)

Power^(f)

(170

)

Discounted cash flow

Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(g)

22 – 39

Estimated auction price for FTRs ($/MW)^(b)

(270) – 2,057

211

Nodal basis ($/MWh)^(g)

(10) – (1)

(3)

Counterparty credit risk (%)^(c)(d)

0.86

(e)

Ameren Illinois credit risk (%)^(c)(d)

0.40

(e)

Fundamental energy production model

Estimated future gas prices ($/mmbtu)^(b)

3 – 4

Escalation rate (%)^(b)(h)

(e)

Contract price allocation

Estimated renewable energy credit costs ($/credit)^(b)

5 – 7

Uranium

—

)

Option model

Volatilities (%)^(b)

(e)

Discounted cash flow

Average forward uranium pricing ($/pound)^(b)

35 – 42

Ameren Missouri credit risk (%)^(c)(d)

0.40

(e)



		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Weighted Average
2015
	Natural gas	$	1	$	(1	)	Option model	Volatilities (%)^(b)	35 – 55	45
								Nodal basis ($/mmbtu)^(c)	(0.30) – 0	(0.20)
							Discounted cash flow	Nodal basis ($/mmbtu)^(b)	(0.10) – 0	(0.10)
								Counterparty credit risk (%)^(c)(d)	0.40 – 12	7
								Ameren Missouri credit risk (%)^(c)(d)	0.40	(e)
	Power^(f)	16		(170		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(g)	22 – 39	29
								Estimated auction price for FTRs ($/MW)^(b)	(270) – 2,057	211
								Nodal basis ($/MWh)^(g)	(10) – (1)	(3)
								Counterparty credit risk (%)^(c)(d)	0.86	(e)
								Ameren Illinois credit risk (%)^(c)(d)	0.40	(e)
							Fundamental energy production model	Estimated future gas prices ($/mmbtu)^(b)	3 – 4	4
								Escalation rate (%)^(b)(h)	3	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)^(b)	5 – 7	6
	Uranium	—		(1		)	Option model	Volatilities (%)^(b)	20	(e)
							Discounted cash flow	Average forward uranium pricing ($/pound)^(b)	35 – 42	37
								Ameren Missouri credit risk (%)^(c)(d)	0.40	(e)


(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 2020. Valuations beyond 2020 use fundamentally modeled pricing by month for peak and off-peak demand.


(g)	The balance at Ameren is comprised of Ameren Missouri and Ameren Illinois power contracts, which respond differently to unobservable input changes due to their opposing positions.


(h)	Escalation rate applies to power prices in 2031 and beyond for ~~June~~September 30, 2016, and to power prices in 2026 and beyond for December 31, 2015.

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 ~~six~~nine months of 2016 or 2015. At ~~June~~September 30, 2016, and December 31, 2015, the counterparty default risk valuation adjustment related to derivative contracts was immaterial for Ameren, Ameren Missouri, and Ameren Illinois.

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 ~~June~~September 30, 2016:


		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				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):										Derivative assets – commodity contracts^(a):
											Fuel oils	$	—	$	—	$	1	$	1
	Natural gas	$	1	$	5	$	—	$	6		Natural gas	$	—	$	3	$	—	$	3
	Power	—		—		15		15			Power	—		—		11		11
	Total derivative assets – commodity contracts	$	1	$	5	$	15	$	21		Total derivative assets – commodity contracts	$	—	$	3	$	12	$	15
	Nuclear decommissioning trust fund:										Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1		Cash and cash equivalents	$	3	$	—	$	—	$	3
	Equity securities:										Equity securities:
	U.S. large capitalization	378		—		—		378			U.S. large capitalization	393		—		—		393
	Debt securities:										Debt securities:
	U.S. treasury and agency securities	—		129		—		129			U.S. treasury and agency securities	—		120		—		120
	Corporate bonds	—		56		—		56			Corporate bonds	—		64		—		64
	Other	—		16		—		16			Other	—		17		—		17
	Total nuclear decommissioning trust fund	$	379	$	201	$	—	$	580	^(b)	Total nuclear decommissioning trust fund	$	396	$	201	$	—	$	597	^(b)
	Total Ameren	$	380	$	206	$	15	$	601		Total Ameren	$	396	$	204	$	12	$	612
Ameren	Derivative assets – commodity contracts^(a):										Derivative assets – commodity contracts^(a):
Missouri	Natural gas	$	—	$	1	$	—	$	1		Fuel oils	$	—	$	—	$	1	$	1
	Power	—		—		15		15			Power	—		—		11		11
	Total derivative assets – commodity contracts	$	—	$	1	$	15	$	16		Total derivative assets – commodity contracts	$	—	$	—	$	12	$	12
	Nuclear decommissioning trust fund:										Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1		Cash and cash equivalents	$	3	$	—	$	—	$	3
	Equity securities:										Equity securities:
	U.S. large capitalization	378		—		—		378			U.S. large capitalization	393		—		—		393
	Debt securities:										Debt securities:
	U.S. treasury and agency securities	—		129		—		129			U.S. treasury and agency securities	—		120		—		120
	Corporate bonds	—		56		—		56			Corporate bonds	—		64		—		64
	Other	—		16		—		16			Other	—		17		—		17
	Total nuclear decommissioning trust fund	$	379	$	201	$	—	$	580	^(b)	Total nuclear decommissioning trust fund	$	396	$	201	$	—	$	597	^(b)
	Total Ameren Missouri	$	379	$	202	$	15	$	596		Total Ameren Missouri	$	396	$	201	$	12	$	609
Ameren	Derivative assets – commodity contracts^(a):										Derivative assets – commodity contracts^(a):
Illinois	Natural gas	$	1	$	4	$	—	$	5		Natural gas	$	—	$	3	$	—	$	3
Liabilities:
Ameren	Derivative liabilities – commodity contracts^(a):										Derivative liabilities – commodity contracts^(a):
	Fuel oils	$	14	$	—	$	—	$	14		Fuel oils	$	9	$	—	$	—	$	9
	Natural gas	—		25		1		26			Natural gas	—		27		—		27
	Power	—		—		170		170			Power	—		—		174		174
	Uranium	—		—		4		4			Uranium	—		—		5		5
	Total Ameren	$	14	$	25	$	175	$	214		Total Ameren	$	9	$	27	$	179	$	215
Ameren	Derivative liabilities – commodity contracts^(a):										Derivative liabilities – commodity contracts^(a):
Missouri	Fuel oils	$	14	$	—	$	—	$	14		Fuel oils	$	9	$	—	$	—	$	9
	Natural gas	—		9		—		9			Natural gas	—		9		—		9
	Power	—		—		1		1			Power	—		—		2		2
	Uranium	—		—		4		4			Uranium	—		—		5		5
	Total Ameren Missouri	$	14	$	9	$	5	$	28		Total Ameren Missouri	$	9	$	9	$	7	$	25
Ameren	Derivative liabilities – commodity contracts^(a):										Derivative liabilities – commodity contracts^(a):
Illinois	Natural gas	$	—	$	16	$	1	$	17		Natural gas	$	—	$	18	$	—	$	18
	Power	—		—		169		169			Power	—		—		172		172
	Total Ameren Illinois	$	—	$	16	$	170	$	186		Total Ameren Illinois	$	—	$	18	$	172	$	190


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


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

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2015:



		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):
	Natural gas	$	—	$	1	$	1	$	2
	Power	—		—		16		16
	Total derivative assets – commodity contracts	$	—	$	1	$	17	$	18
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	4	$	—	$	—	$	4
	Equity securities:
	U.S. large capitalization	364		—		—		364
	Debt securities:
	U.S. treasury and agency securities	—		109		—		109
	Corporate bonds	—		58		—		58
	Other	—		22		—		22
	Total nuclear decommissioning trust fund	$	368	$	189	$	—	$	557	^(b)
	Total Ameren	$	368	$	190	$	17	$	575
Ameren	Derivative assets – commodity contracts^(a):
Missouri	Natural gas	$	—	$	—	$	1	$	1
	Power	—		—		16		16
	Total derivative assets – commodity contracts	$	—	$	—	$	17	$	17
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	4	$	—	$	—	$	4
	Equity securities:
	U.S. large capitalization	364		—		—		364
	Debt securities:
	U.S. treasury and agency securities	—		109		—		109
	Corporate bonds	—		58		—		58
	Other	—		22		—		22
	Total nuclear decommissioning trust fund	$	368	$	189	$	—	$	557	^(b)
	Total Ameren Missouri	$	368	$	189	$	17	$	574
Ameren	Derivative assets – commodity contracts^(a):
Illinois	Natural gas	$	—	$	1	$	—	$	1
Liabilities:
Ameren	Derivative liabilities – commodity contracts^(a):
	Fuel oils	$	29	$	—	$	—	$	29
	Natural gas	1		62		1		64
	Power	—		—		170		170
	Uranium	—		—		1		1
	Total Ameren	$	30	$	62	$	172	$	264
Ameren	Derivative liabilities – commodity contracts^(a):
Missouri	Fuel oils	$	29	$	—	$	—	$	29
	Natural gas	—		13		1		14
	Uranium	—		—		1		1
	Total Ameren Missouri	$	29	$	13	$	2	$	44
Ameren	Derivative liabilities – commodity contracts^(a):
Illinois	Natural gas	$	1	$	49	$	—	$	50
	Power	—		—		170		170
	Total Ameren Illinois	$	1	$	49	$	170	$	220


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


(b)	Balance excludes $(1) million of receivables, payables, and accrued income, net.

~~The following table summarizes the changes in the fair value of~~All costs related to financial assets and liabilities classified as Level 3 in the fair value hierarchy ~~for~~are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. For the three and nine months ended ~~June~~September 30, 2016: and 2015, the balances and changes in the fair value of Level 3 financial assets and liabilities associated with fuel oils, natural gas, and uranium were immaterial.

Net derivative commodity contracts

Ameren
Missouri

Ameren
Illinois
Ameren
Natural gas:
Beginning balance at April 1, 2016 $ —
$ (1 ) $ (1 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities —
(1 ) (1 )
Settlements —
1
1
Ending balance at June 30, 2016 $ —
$ (1 ) $ (1 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2016 $ —
$ (1 ) $ (1 )
Power:
Beginning balance at April 1, 2016 $ 6
$ (187 ) $ (181 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities (1 ) 14
13
Purchases 13
—
13
Settlements (4 ) 4
—
Ending balance at June 30, 2016 $ 14
$ (169 ) $ (155 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2016 $ —
$ 14
$ 14
Uranium:
Beginning balance at April 1, 2016 $ (4 ) $ (a)
$ (4 )
Ending balance at June 30, 2016 $ (4 ) $ (a)
$ (4 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2016 $ —
$ (a)
$ —


~~(a)~~	~~Not applicable.~~

The following table summarizes the changes in the fair value of power financial assets and liabilities classified as Level 3 in the fair value ~~hierarchy for the~~ ~~three months ended June 30, 2015~~:hierarchy:

Net derivative commodity contracts

Ameren
Missouri

Ameren
Illinois
Ameren
Fuel oils:
Beginning balance at April 1, 2015 $ (6 ) $ (a)
$ (6 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities 1
(a)
1
Settlements 2
(a)
2
Transfers out of Level 3 2
(a)
2
Ending balance at June 30, 2015 $ (1 ) $ (a)
$ (1 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2015 $ 3
$ (a)
$ 3
Natural gas:
Beginning balance at April 1, 2015 $ (1 ) $ 1
$ —
Purchases —
(1 ) (1 )
Settlements 1
(1 ) —
Ending balance at June 30, 2015 $ —
$ (1 ) $ (1 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2015 $ —
$ —
$ —
Power:
Beginning balance at April 1, 2015 $ 4
$ (164 ) $ (160 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities —
(4 ) (4 )
Purchases 29
—
29
Settlements (6 ) 3
(3 )
Ending balance at June 30, 2015 $ 27
$ (165 ) $ (138 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2015 $ 1
$ (5 ) $ (4 )
Uranium:
Beginning balance at April 1, 2015 $ (1 ) $ (a)
$ (1 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities (1 ) (a)
(1 )
Ending balance at June 30, 2015 $ (2 ) $ (a)
$ (2 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2015 $ (1 ) $ (a)
$ (1 )



		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
For the three months ended September 30, 2016
Beginning balance at July 1, 2016	$	14		$	(169	)	$	(155	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			(6	)		(6	)
Settlements		(5	)		3			(2	)
Ending balance at September 30, 2016	$	9		$	(172	)	$	(163	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2016	$	—		$	(2	)	$	(2	)
For the three months ended September 30, 2015
Beginning balance at July 1, 2015	$	27		$	(165	)	$	(138	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		2			(8	)		(6	)
Settlements		(7	)		3			(4	)
Ending balance at September 30, 2015	$	22		$	(170	)	$	(148	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2015	$	1		$	(7	)	$	(6	)
For the nine months ended September 30, 2016
Beginning balance at January 1, 2016	$	16		$	(170	)	$	(154	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(4	)		(13	)		(17	)
Purchases		13			—			13
Settlements		(16	)		11			(5	)
Ending balance at September 30, 2016	$	9		$	(172	)	$	(163	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2016	$	—		$	(7	)	$	(7	)
For the nine months ended September 30, 2015
Beginning balance at January 1, 2015	$	9		$	(142	)	$	(133	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			(37	)		(37	)
Purchases		29			—			29
Settlements		(16	)		9			(7	)
Ending balance at September 30, 2015	$	22		$	(170	)	$	(148	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2015	$	1		$	(35	)	$	(34	)


~~(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 six months ended June 30, 2016:~~

Net derivative commodity contracts

Ameren
Missouri

Ameren
Illinois
Ameren
Natural gas:
Beginning balance at January 1, 2016 $ —
$ —
$ —
Realized and unrealized gains (losses) included in regulatory assets/liabilities —
(1 ) (1 )
Ending balance at June 30, 2016 $ —
$ (1 ) $ (1 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2016 $ —
$ (1 ) $ (1 )
Power:
Beginning balance at January 1, 2016 $ 16
$ (170 ) $ (154 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities (4 ) (7 ) (11 )
Purchases 13
—
13
Settlements (11 ) 8
(3 )
Ending balance at June 30, 2016 $ 14
$ (169 ) $ (155 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2016 $ —
$ (5 ) $ (5 )
Uranium:
Beginning balance at January 1, 2016 $ (1 ) $ (a)
$ (1 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities (3 ) (a)
(3 )
Ending balance at June 30, 2016 $ (4 ) $ (a)
$ (4 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2016 $ (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 six months ended June 30, 2015:~~

Net derivative commodity contracts

Ameren
Missouri

Ameren
Illinois
Ameren
Fuel oils:
Beginning balance at January 1, 2015 $ (6 ) $ (a)
$ (6 )
Settlements 3
(a)
3
Transfers out of Level 3 2
(a)
2
Ending balance at June 30, 2015 $ (1 ) $ (a)
$ (1 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2015 $ —
$ (a)
$ —
Natural gas:
Beginning balance at January 1, 2015 $ (1 ) $ —
$ (1 )
Settlements 1
(1 ) —
Ending balance at June 30, 2015 $ —
$ (1 ) $ (1 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2015 $ —
$ —
$ —
Power:
Beginning balance at January 1, 2015 $ 9
$ (142 ) $ (133 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities (2 ) (29 ) (31 )
Purchases 29
—
29
Settlements (9 ) 6
(3 )
Ending balance at June 30, 2015 $ 27
$ (165 ) $ (138 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2015 $ —
$ (29 ) $ (29 )
Uranium:
Beginning balance at January 1, 2015 $ (2 ) $ (a)
$ (2 )
Ending balance at June 30, 2015 $ (2 ) $ (a)
$ (2 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2015 $ —
$ (a)
$ —


~~(a)~~	~~Not applicable.~~

Transfers into 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 1 and Level 3 for fuel oils were primarily caused by changes in availability of similar financial trades observable on electronic exchanges between the periods. 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 ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, there were no material transfers between Level 1 and Level 2, Level 1 and Level 3, or ~~between~~ Level 2 and Level 3 related to derivative commodity contracts.

The Ameren Companies’ carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments. They are considered to be Level 1 in the fair value hierarchy. The Ameren Companies' short-term borrowings also approximate fair value because of their short-term nature. Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments, which fair value measurement is considered to be 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 ~~June~~September 30, 2016, and December 31, 2015:


	June 30, 2016				December 31, 2015				September 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:
Long-term debt and capital lease obligations (including current portion)	$	7,036	$	7,973	$	7,275	$	7,814	$	7,038	$	7,971	$	7,275	$	7,814
Preferred stock^(a)	142		127		142		125		142		131		142		125
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	3,999	$	4,539	$	4,110	$	4,449	$	4,000	$	4,551	$	4,110	$	4,449
Preferred stock	80		77		80		75		80		79		80		75
Ameren Illinois:
Long-term debt (including current portion)	$	2,343	$	2,692	$	2,471	$	2,665	$	2,344	$	2,682	$	2,471	$	2,665
Preferred stock	62		50		62		50		62		52		62		50


(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 ~~Agreement~~Agreements

In April and September 2016, Ameren Illinois conducted a procurement ~~event,~~events, administered by the IPA, to purchase energy ~~products through May 31, 2019.~~products. Ameren Missouri was among the winning suppliers in ~~this event.~~these events. As a result, in April 2016, Ameren Missouri and Ameren Illinois entered into an energy product agreement by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, 375,200 megawatthours at an average price of $34.71 per megawatthour during the period of June 1, 2017, through September 30, 2018. In September 2016, Ameren Missouri and Ameren Illinois entered into an energy product agreement by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, 82,800 megawatthours at an average price of $34.35 per megawatthour during the period of May 1, 2017, through September 30, 2018.

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


				Three Months				Six Months						Three Months				Nine Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2016	$	3	$	(a)	$	12	$	(a)	Operating Revenues	2016	$	9	$	(a)	$	21	$	(a)
agreements with Ameren Illinois		2015		4		(a)		5		(a)		2015		4		(a)		9		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2016		7		1		13		2	Operating Revenues	2016		5		1		18		3
rent and facility services		2015		7		1		13		2		2015		6		1		19		3
Ameren Missouri and Ameren Illinois	Operating Revenues	2016		(b)		(b)		(b)		(b)	Operating Revenues	2016		1		(b)		1		(b)
miscellaneous support services		2015		1		(b)		1		(b)		2015		1		(b)		2		(b)
Total Operating Revenues		2016	$	10	$	1	$	25	$	2		2016	$	15	$	1	$	40	$	3
		2015		12		1		19		2		2015		11		1		30		3
Ameren Illinois power supply	Purchased Power	2016	$	(a)	$	3	$	(a)	$	12	Purchased Power	2016	$	(a)	$	9	$	(a)	$	21
agreements with Ameren Missouri		2015		(a)		4		(a)		5		2015		(a)		4		(a)		9
Ameren Illinois transmission	Purchased Power	2016		(a)		1		(a)		1	Purchased Power	2016		(a)		1		(a)		2
services with ATXI		2015		(a)		(b)		(a)		1		2015		(a)		1		(a)		2
Total Purchased Power		2016	$	(a)	$	4	$	(a)	$	13		2016	$	(a)	$	10	$	(a)	$	23
		2015		(a)		4		(a)		6		2015		(a)		5		(a)		11
Ameren Services support services	Other Operations and Maintenance	2016	$	32	$	30	$	66	$	61	Other Operations and Maintenance	2016	$	30	$	29	$	96	$	90
agreement		2015		32		30		66		59		2015		30		28		96		87
Money pool borrowings (advances)	Interest Charges/ Miscellaneous Income	2016	$	(b)	$	(b)	$	(b)	$	(b)	Interest Charges/ Miscellaneous Income	2016	$	(b)	$	(b)	$	(b)	$	(b)
		2015		(b)		(b)		(b)		(b)		2015		(b)		(b)		(b)		(b)


(a)	Not applicable.


(b)	Amount less than $1 million.

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 2 – Rate and Regulatory Matters, Note 8 – Related Party Transactions, and Note 10 – Callaway Energy Center.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at ~~June~~September 30, 2016. The property coverage and the nuclear liability coverage ~~must be renewed on~~renewal dates are April 1 and January 1, respectively, of each year. Both coverages were renewed in 2016.



Type and Source of Coverage	Maximum Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	375		$	—
Pool participation	12,986		^(a)	127		^(b)
	$	13,361	^(c)	$	127
Property damage:
NEIL	$	2,750	^(d)	$	30	^(e)
European Mutual Association for Nuclear Insurance	450		^(f)	—
	$	3,200		$	30
Replacement power:
NEIL	$	490	^(g)	$	7	^(e)


(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 $127 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 $2.75 billion in property damage, decontamination, and premature decommissioning insurance for radiation events. NEIL provides $2.3 billion in property damage for nonradiation events.


(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 $450 million in excess of the $2.75 billion and $2.3 billion property coverage for radiation and nonradiation events, respectively, 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 twelve 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 $328 million.

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 most recent five-year inflationary adjustment became effective in September 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 insurance policies, subject to an industrywide aggregate policy limit of $3.24 billion within a 12-month period, or $1.83 billion for events not involving radiation contamination.

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

ToIn order to supply a portion of the fuel requirements of Ameren Missouri’s energy centers, Ameren Missouri has entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. Additionally, Ameren Missouri and Ameren Illinois have entered into various long-term commitments for purchased power and natural gas for distribution. At ~~June~~September 30, 2016, total obligations related to commitments for coal, natural gas, nuclear fuel, purchased power, methane gas, equipment, and meter reading services, among other agreements, at Ameren, Ameren Missouri, and Ameren Illinois were ~~$4,465~~$4,328 million, ~~$2,614~~$2,428 million, and ~~$1,790~~$1,859 million, respectively. For additional information regarding our obligations and commitments at December 31, 2015, see Note 15 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

In April and September 2016, Ameren Illinois conducted a procurement ~~event,~~events, administered by the IPA, to purchase energy products and capacity through May 31, 2019. In ~~this~~the April procurement event, Ameren Illinois contracted to purchase approximately 3,609,800 megawatthours of energy products for $105 million from June 1, 2016, through May 31, 2019. In the September procurement event, Ameren Illinois contracted to purchase approximately 2,229,800 megawatthours of energy products for $71 million from October 1, 2016, through May 31, 2019. In addition, in the September procurement event, Ameren Illinois contracted to purchase 1,854 MWs of capacity for $96 million from June 1, 2017, through May 31, 2019. The results of both procurement events are included in Ameren’s and Ameren Illinois’ obligations discussed above. See Note 8 – Related Party Transactions for additional information regarding ~~the~~ energy product ~~agreement~~agreements between Ameren Missouri and Ameren Illinois as a result of ~~this~~these procurement ~~event.~~events.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. Such requirements can impact the siting, development and operation of new and existing generation, transmission, distribution and natural gas storage facilities. Such requirements can encompass emissions, discharges to water, water usage, impacts to air, land, and water, and chemical and waste handling. Complex and

lengthy approval processes are required to obtain, modify or renew permits and licenses for new or existing facilities. Additionally, the use and handling of various chemicals or hazardous materials at some of our facilities require release prevention plans and emergency response procedures.

The EPA has promulgated several environmental regulations that will have a significant impact on the electric utility industry. Over time, compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants. Significant new rules include the regulation of CO₂ emissions from existing power plants through the Clean Power Plan and from new power plants through the revised NSPS; the CSAPR, which requires further reductions of SO₂ emissions and NO_x

emissions from power plants; a regulation governing management and storage of CCR; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from power plants; revised NSPS for particulate matter, SO₂, and NO_x emissions from new sources; new effluent standards applicable to wastewater discharges from power plants; and new regulations under the Clean Water Act that could require significant capital expenditures, such as modifications to water intake structures at Ameren Missouri’s energy centers. The EPA also periodically reviews and revises national ambient air quality standards, including those standards associated with emissions from power plants, such as particulate matter, ozone, SO₂and NO_x. Certain of these new regulations are being or 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 future regulations are unknown, the individual or combined effects of new environmental regulations could result in significant capital expenditures and increased operating costs for Ameren and Ameren Missouri. Compliance with all of 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

that these costs would be recoverable through rates, subject to MoPSC prudence review, but the nature and timing of costs and their recovery could result in regulatory lag. As of December 31, 2015, Ameren Missouri’s energy centers that emit CO₂represented approximately 20% and 35% of Ameren’s and Ameren Missouri’s rate base, respectively.

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 and Ameren Missouri estimate that they will need to make capital expenditures of $600 million to $700 million in the aggregate from 2016 through 2020 in order to comply with existing environmental regulations. ~~Additionally,~~ Ameren Missouri may be required to install additional air emissions controls ~~within the next six to 10 years.~~beyond 2020. This estimate of capital expenditures includes ~~capital~~ expenditures required for the CCR regulations, the Clean Water Act rule applicable to cooling water intake structures at existing power plants, and the Clean Water Act effluent limitation guidelines applicable to steam electric generating units, all of which are discussed below. ~~These estimates do~~This estimate does not include the potential impacts of the Clean Power Plan discussed below. The actual amount of capital expenditures 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.

The following sections describe the more significant new environmental laws and rules and environmental enforcement and remediation matters that affect or could affect our operations.

Clean Air Act

Federal and state laws require significant reductions in SO₂and NO_x through either emission source reductions or the use

and retirement of emission allowances. The first phase of the CSAPR emission reduction requirements became effective in 2015 and the second phase of emission reduction requirements, which were revised by the EPA in September 2016, will become effective in 2017; additional emission reduction requirements may apply in subsequent years. To achieve compliance with the CSAPR, Ameren Missouri burns ultra-low-sulfur coal, operates two scrubbers at its Sioux energy center, and optimizes other existing pollution control equipment. Ameren Missouri does not expect to make additional capital investments to comply with the ~~current~~2017 CSAPR requirements. However, Ameren Missouri expects to incur additional costs to lower its emissions at one or more of its energy centers to comply with the CSAPR in future years. These higher costs are expected to be recovered from customers through the FAC or higher base rates.

CO₂ Emissions Standards

The Clean Power Plan, which sets forth CO₂emissions standards applicable to existing power plants, was issued by the EPA in August 2015 but stayed by the United States Supreme Court in February 2016, pending the outcome of various ~~appeals,~~legal challenges, as discussed below.

If upheld, the Clean Power Plan would require Missouri and Illinois to reduce CO₂ emissions from power plants within their states significantly below 2005 levels by 2030. The rule contains interim compliance periods commencing in 2022 that would

require each state to demonstrate progress in achieving its CO₂ emissions reduction target. Ameren continues to evaluate the Clean Power Plan's potential impacts to its operations, including those related to electric system reliability, and to its level of investment in customer energy efficiency programs, renewable energy, and other forms of generation. Significant uncertainty exists regarding the impact of the Clean Power Plan, as its implementation will depend upon plans to be developed by the states. Numerous legal challenges are pending, which could result in the rule being declared invalid or the nature and timing of CO₂ emissions reductions being revised. All implementation requirements are deferred until such time as these legal challenges are concluded. A decision by the District of Columbia Circuit Court of Appeals is expected to be issued in ~~the fourth quarter of 2016 or the first quarter of~~ 2017, and subsequent appeals to the United States Supreme Court are likely. We cannot predict the outcome of such legal challenges or their impact on our results of operations, financial position, or liquidity. If the rule is ultimately upheld and implemented in substantially similar form to the rule when issued, compliance measures could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and natural-gas-fired energy centers, which could result in increased operating costs and require Ameren Missouri to make new or accelerated capital expenditures. Ameren Missouri expects substantially all of these increased costs to be recoverable, subject to MoPSC prudence review, through higher rates to customers, which could be significant.

In 2015, the EPA also issued final regulations that set CO₂ emissions standards for new power plants. These new standards

establish separate emissions limits for new natural-gas-fired combined cycle plants and new coal-fired plants.

Federal and state legislation or regulations that mandate limits on the emission of CO₂ may result in significant increases in capital expenditures and operating costs, which could lead to increased liquidity needs and higher financing costs. Mandatory limits on the emission of CO₂ could increase costs for Ameren Missouri’s 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 recovery in rates of these compliance costs. The cost of Ameren Illinois’ purchased power and gas purchased for resale could increase. However, Ameren Illinois expects these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. Ameren's and Ameren Missouri's earnings might benefit from increased investment to comply with CO₂ emission limitations to the extent that the investments are reflected and recovered on a timely basis 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. ~~Ameren Missouri anticipates that~~A trial was held in the third quarter of 2016. It is not certain when a ~~trial of~~final decision will be reached in this case, ~~will begin in August 2016.~~and subsequent appeals are likely. Ameren Missouri believes its defenses are meritorious and is defending itself vigorously. However, there can be no assurances that it will be successful in its efforts.

The ultimate resolution of this matter could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. A resolution of this matter could result in increased capital expenditures for the installation of pollution control equipment and increased operations and maintenance expenses. We are unable to predict the ultimate resolution of ~~these matters~~this matter or the costs that might be incurred.

Clean Water Act

In 2014, the EPA issued its final rule applicable to cooling water intake structures at existing power plants. The rule requires a case-by-case evaluation and plan for reducing aquatic organisms impinged on the facility’s intake screens or entrained through the plant's cooling water system. Additionally, in 2015, the EPA issued its final rule to revise the effluent limitation guidelines applicable to steam electric generating units. Effluent limitation guidelines are national standards for water discharges that are based on the effectiveness of available control technology. The EPA's rule prohibits effluent discharges of certain waste streams and imposes more stringent limitations on certain components in water discharges from power plants. All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to

the cooling water intake structures rule and all of Ameren Missouri’s coal-fired energy centers are subject to the effluent limitations rule. Implementation of both rules will occur during the renewal process of each energy center’s water discharge ~~permits,~~permit, which will occur between 2018 and 2023. The rules could have an adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity if their implementation requires extensive modifications to the cooling water systems and water discharge systems at Ameren Missouri’s energy centers and if those investments are not recovered on a timely basis in electric rates charged to Ameren Missouri’s customers.

Ash Management

In 2015, the EPA issued regulations regarding the management and disposal of CCR. These regulations ~~will~~ affect CCR disposal and handling costs at Ameren Missouri's energy centers. The regulations allow for the management of CCR as a solid waste, as well as for its continued beneficial uses, ~~such as recycling,~~ which could reduce the amount to be disposed. The regulations also establish criteria regarding the structural integrity, location, groundwater monitoring, and operation of CCR impoundments and landfills. They require ~~groundwater monitoring, and~~ closure of impoundments if the ~~groundwater standards~~criteria are not achieved. Ameren Missouri's capital expenditure plan includes the cost of constructing landfills as part of its environmental compliance plan.

The new regulations do not apply to ash ponds at plants no longer in ~~operation, such as Ameren’s Meredosia and Hutsonville energy centers.~~operation.

Remediation

The Ameren Companies are involved in a number of remediation actions to clean up sites impacted by the use or disposal of materials containing hazardous substances. Federal and state laws can require responsible parties to 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 federal or state governments as a potentially responsible party at several contaminated sites.

As of ~~June~~September 30, 2016, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois, which are in various stages of investigation, evaluation, remediation, and closure. Ameren Illinois estimates it could substantially conclude remediation efforts by 2025. The ICC allows Ameren Illinois to recover remediation and litigation costs associated with its former MGP sites from its electric and natural gas utility customers through environmental adjustment rate riders. Costs are subject to annual review by the ICC. As of ~~June~~September 30, 2016, Ameren Illinois estimated the obligation related to these former MGP sites at ~~$217~~$204 million to ~~$306~~$274 million. Ameren and Ameren Illinois recorded a liability of ~~$217~~$204 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate.

The scope ~~and extent to which~~of the remediation activities at these former MGP sites ~~are remediated~~ may increase as remediation efforts continue. Considerable uncertainty remains in these estimates because many site-specific factors can influence the ultimate actual costs, including 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 is also responsible for the cleanup of some underground storage tanks and a water treatment plant in Illinois. As of June 30, 2016, Ameren Illinois recorded a liability of $0.7 million to represent its best estimate of its obligation for these sites.

~~In 2008, the EPA issued an administrative order to three companies, including Ameren~~ Missouri to conduct a site investigation at a former coal tar distillery in St. Louis, Missouri. 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. Site investigation activities and studies are complete, and reports have been submitted to the EPA for review. Based upon the results of those studies, it is unlikely that further remediation will be required. Accordingly, as of June 30, 2016, Ameren Missouri did not record a liability for remediation at this site.

~~Ameren Missouri also~~ participated in the investigation of various sites known as Sauget Area 2 located in Sauget, Illinois.

In 2000, the EPA notified Ameren Missouri and numerous other companies ~~including Solutia, Inc.,~~ that former landfills and lagoons at those sites may contain soil and groundwater contamination. From about 1926 until 1976, Ameren Missouri operated an energy center adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property at Sauget Area 2 that was once used by others as a landfill.

In December 2013, the EPA issued its record of decision for Sauget Area 2 approving the investigation and the remediation actions 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 ~~June~~September 30, 2016, 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 June 30, 2016, Ameren Missouri estimated and recorded a $0.6 million liability related to the site. Although monitoring will continue for some time, no significant remediation measures are anticipated.

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.

Ameren Missouri Municipal Taxes

The cities of Creve Coeur and Winchester, Missouri, on behalf of themselves and other municipalities in Ameren Missouri’s service area, filed a class action lawsuit in November 2011, against Ameren Missouri in the Circuit Court of St. Louis County, Missouri. The lawsuit alleges that Ameren Missouri failed to collect and pay gross receipts taxes or license fees on certain revenues, including revenues from wholesale power and interchange sales. Ameren and Ameren Missouri recorded immaterial liabilities on their respective balance sheets as of ~~June~~September 30, 2016, and December 31, 2015, representing their estimate of the probable ~~taxes and fees~~loss due as a result of this lawsuit. Ameren and Ameren Missouri ~~believes~~believe there is a remote possibility that a liability relating to this lawsuit could be material to Ameren and Ameren Missouri’s results of operations, financial position, and liquidity. Ameren Missouri believes its defenses are meritorious and is defending itself vigorously. However, there can be no assurances that Ameren Missouri will be successful in its efforts.

NOTE 10 – CALLAWAY ENERGY CENTER

Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. Under the NWPA, Ameren

and other utilities that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established

the fee that these utilities pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatthour generated and sold by those plants. The NWPA also requires the DOE to review the nuclear waste fee annually 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 DOE. Consistent with the NWPA and its standard contract, which stated that the DOE would begin to dispose of spent nuclear fuel by 1998, Ameren Missouri had historically collected one mill from its electric customers for each kilowatthour of electricity that it generated and sold from its Callaway energy center. Because the federal government is not meeting its disposal obligation, the collection of this fee ~~has been~~was suspended ~~since~~in May 2014.

~~Although both the NWPA and the standard contract stated that the DOE would begin to dispose of spent nuclear fuel by 1998, the DOE is not meeting its disposal obligation.~~ 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.

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 sued the DOE to recover costs, such as certain NRC fees and ad valorem taxes, incurred for ongoing storage of their spent fuel. The lawsuit resulted in a settlement agreement that provides for annual ~~recovery~~reimbursement of additional spent fuel storage and related costs. Ameren Missouri will continue to apply for reimbursement from the DOE for allowable costs associated with the ongoing storage of spent fuel.

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 the expected life of the nuclear energy center. 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 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. In April 2016, the MoPSC approved no change in electric service rates for decommissioning costs based on Ameren Missouri’s updated cost study and funding analysis filed in April 2015.

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. If the assumed return on trust

assets is not earned, Ameren Missouri believes that it is probable that any such earnings deficiency will be recovered in rates.

NOTE 11 – RETIREMENT BENEFITS

The following table presents the components of the net periodic benefit cost (benefit) incurred for Ameren’s pension and postretirement benefit plans for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Pension Benefits												Postretirement Benefits												Pension Benefits												Postretirement Benefits
	Three Months						Six Months						Three Months						Six Months						Three Months						Nine Months						Three Months						Nine Months
	2016			2015			2016			2015			2016			2015			2016			2015			2016			2015			2016			2015			2016			2015			2016			2015
Service cost	$	20		$	22		$	40		$	46		$	5		$	6		$	10		$	11		$	20		$	23		$	60		$	69		$	5		$	6		$	15		$	17
Interest cost	45			43			92			87			12			12			24			24			46			43			138			130			12			12			36			36
Expected return on plan assets	(63		)	(62		)	(126		)	(124		)	(18		)	(17		)	(36		)	(34		)	(63		)	(62		)	(189		)	(186		)	(18		)	(17		)	(54		)	(51		)
Amortization of:
Prior service benefit	—			—			—			—			(1		)	(1		)	(2		)	(2		)	—			—			—			—			(1		)	(1		)	(3		)	(3		)
Actuarial loss (gain)	7			19			16			37			(2		)	2			(5		)	3			8			19			24			56			(3		)	1			(8		)	4
Settlement loss	—			1			—			1			—			—			—			—			—			—			—			1			—			—			—			—
Net periodic benefit cost (benefit)	$	9		$	23		$	22		$	47		$	(4	)	$	2		$	(9	)	$	2		$	11		$	23		$	33		$	70		$	(5	)	$	1		$	(14	)	$	3

Ameren Missouri and Ameren Illinois are responsible for their respective shares of Ameren’s pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs (benefit) incurred for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Pension Benefits										Postretirement Benefits												Pension Benefits										Postretirement Benefits
	Three Months					Six Months					Three Months						Six Months						Three Months					Nine Months					Three Months						Nine Months
	2016			2015		2016			2015		2016			2015			2016			2015			2016			2015		2016			2015		2016			2015			2016			2015
Ameren Missouri^(a)	$	5		$	13	$	13		$	28	$	(1	)	$	3		$	(2	)	$	4		$	6		$	14	$	19		$	42	$	(1	)	$	2		$	(3	)	$	6
Ameren Illinois	6			10		11			19		(3		)	(1		)	(7		)	(2		)	6			9		17			28		(3		)	—			(10		)	(2		)
Other	(2		)	—		(2		)	—		—			—			—			—			(1		)	—		(3		)	—		(1		)	(1		)	(1		)	(1		)
Ameren^(a)(b)	$	9		$	23	$	22		$	47	$	(4	)	$	2		$	(9	)	$	2		$	11		$	23	$	33		$	70	$	(5	)	$	1		$	(14	)	$	3


(a)	Does not include the impact of the regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates.


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

NOTE 12 – DISCONTINUED OPERATIONS

There was no net income attributable to Ameren common shareholders from discontinued operations during 2016. 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, 2015:



	2015			2015
	Three Months			Nine Months
Operating revenues	$	—		$	—
Operating benefits (expenses)	(1		)	2
Operating income (loss) before income tax	(1		)	2
Income tax benefit	1			50
Income from discontinued operations, net of taxes	$	—		$	52

During the second quarter of 2015, based on the completion of the IRS audit for 2013, Ameren removed a previously recorded reserve for unrecognized tax benefits and recognized a tax benefit from discontinued operations. See Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information related to discontinued operations.

All matters related to the final tax basis of New AER and the related tax benefit resulting from the divested merchant generation business were resolved with the completion of the IRS audit for 2013. During the second quarter of 2015, based on the completion of the IRS audit, Ameren removed a reserve for unrecognized tax benefits recorded in 2013 and recognized a tax benefit from discontinued operations.

~~The following table presents the components of discontinued operations in Ameren's consolidated statement of income for the three and six months ended June 30, 2016 and 2015:~~

Three Months Six Months
2016 2015 2016 2015
Operating revenues $ —
$ —
$ —
$ —

Operating benefits (expenses) —
—
—
3

Operating income before income tax —
—
—
3

Income tax benefit —
52
—
49

Income from discontinued operations, net of taxes $ —
$ 52
$ —
$ 52

The following table presents the carrying amounts of the components of assets and liabilities of Ameren’s discontinued operations, which consist primarily of AROs and related deferred income tax assets associated with the abandoned Meredosia and Hutsonville energy centers, at ~~June~~September 30, 2016, and December 31, 2015:


	June 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Assets of discontinued operations
Accumulated deferred income taxes, net	$	14	$	14	$	15	$	14
Total assets of discontinued operations	$	14	$	14	$	15	$	14
Liabilities of discontinued operations
Accounts payable and other current obligations	$	1	$	1	$	1	$	1
Asset retirement obligations^(a)	26		28		26		28
Total liabilities of discontinued operations	$	27	$	29	$	27	$	29


(a)	Ameren has ~~demolished and~~ completed its retirement obligations at the Hutsonville energy center. The remaining ARO liabilities relate to the abandoned Meredosia energy center.

NOTE 13 – SEGMENT INFORMATION

Ameren has two reportable segments: Ameren Missouri and Ameren Illinois. Ameren Missouri and Ameren Illinois each have one reportable segment. The Ameren Missouri segment for both Ameren and Ameren Missouri includes all of the operations of Ameren Missouri’s business as described in Note 1 – Summary of Significant Accounting Policies. The Ameren Illinois segment for both Ameren and Ameren Illinois includes all of the operations of Ameren Illinois’ business as described in Note 1 – Summary of Significant Accounting Policies. The category called Other primarily includes Ameren parent company activities, Ameren Services, and ATXI.

The following table presents information about the reported revenues and net income attributable to Ameren common shareholders from continuing operations for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, and total assets of continuing operations as of ~~June~~September 30, 2016, and December 31, 2015:


Three Months	Ameren Missouri		Ameren Illinois		Other		Intersegment Eliminations			Ameren			Ameren Missouri		Ameren Illinois		Other		Intersegment Eliminations			Ameren
2016
External revenues	$	857	$	541	$	29	$	—		$	1,427		$	1,150	$	675	$	34	$	—		$	1,859
Intersegment revenues	10		1		1		(12		)	—			15		1		1		(17		)	—
Net income attributable to Ameren common shareholders from continuing operations	92		45		10		—			147			241		119		9		—			369
2015
External revenues	$	872	$	512	$	17	$	—		$	1,401		$	1,160	$	654	$	19	$	—		$	1,833
Intersegment revenues	12		1		—		(13		)	—			11		1		1		(13		)	—
Net income attributable to Ameren common shareholders from continuing operations	61		31		6		—			98			239		98		6		—			343
Six Months
Nine Months
2016
External revenues	$	1,583	$	1,217	$	61	$	—		$	2,861		$	2,733	$	1,892	$	95	$	—		$	4,720
Intersegment revenues	25		2		1		(28		)	—			40		3		2		(45		)	—
Net income attributable to Ameren common stockholders from continuing operations	106		104		42		—			252
Net income attributable to Ameren common shareholders from continuing operations													347		223		51		—			621
2015
External revenues	$	1,665	$	1,256	$	36	$	—		$	2,957		$	2,825	$	1,910	$	55	$	—		$	4,790
Intersegment revenues	19		2		1		(22		)	—			30		3		2		(35		)	—
Net income (loss) attributable to Ameren common stockholders from continuing operations	102		84		20		—			206
As of June 30, 2016:
Net income attributable to Ameren common shareholders from continuing operations													341		182		26		—			549
As of September 30, 2016:
Total assets	$	13,649	$	8,999	$	1,276	$	(145	)	$	23,779	^(a)	$	13,889	$	9,202	$	1,496	$	(468	)	$	24,119	^(a)
As of December 31, 2015:
Total assets	$	13,851	$	8,903	$	1,139	$	(267	)	$	23,626	^(a)	$	13,851	$	8,903	$	1,139	$	(267	)	$	23,626	^(a)

(a) Excludes total assets from discontinued operations of $15 million and $14 million as of ~~June~~September 30, 2016, and December 31, ~~2015.~~2015, respectively.

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.

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 rate-regulated electric and natural gas transmission and distribution businesses in Illinois.

Additionally, Ameren has a subsidiary, ATXI, that operates a FERC rate-regulated electric transmission business. ATXI is developing MISO-approved electric transmission projects, including the Illinois Rivers, Spoon River, and Mark Twain projects. Ameren is also pursuing projects to improve electric transmission system reliability within Ameren Missouri’s and Ameren Illinois’ service territories as well as evaluating competitive electric transmission investment opportunities outside of these territories, including investments outside of MISO. Ameren also has various other subsidiaries that conduct activities such as the provision of shared services.

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. See Note 12 – Discontinued Operations under Part I, Item 1, of this report and Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information regarding the divestiture transactions and discontinued operations presentation.

Ameren’s financial statements are prepared on a consolidated basis, and therefore include the accounts of its

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

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

OVERVIEW

Net income attributable to Ameren common shareholders from continuing operations was ~~$147~~$369 million in the ~~second~~third quarter of 2016, compared with ~~$98~~$343 million in the year-ago period. Net income attributable to Ameren common shareholders from continuing operations was ~~$252~~$621 million in the first ~~six~~nine months of 2016, compared with ~~$206~~$549 million in the year-ago period. Net income was favorably affected in the ~~second~~third quarter and the first ~~six~~nine months of 2016, compared with the year-ago periods, by increased Ameren Illinois and ATXI electric transmission service and Ameren Illinois electric distribution service earnings, reflecting Ameren’s strategy to allocate incremental capital to those businesses; increased demand due to warmer summer temperatures; increased rates for Ameren Illinois’ natural gas distribution service pursuant to a December 2015 order; decreased other operations and maintenance expenses; and the recognition of a MEEIA 2013 performance incentive. Net income was also favorably affected in the first nine months of 2016, compared with the year-ago period, by the absence of a provision recognized in the second quarter of 2015, as a result of Ameren Missouri’s discontinued efforts to license and build a second nuclear unit at its existing Callaway energy center site. Net income was also favorably affected by increased Ameren Illinois and ATXI electric transmission service and Ameren Illinois electric distribution service earnings, reflecting Ameren’s strategy to allocate incremental capital to those businesses; increased rates for Ameren Illinois’ natural gas distribution service pursuant to a December 2015 order; and decreased operations and maintenance expenses. In the first six months of 2016, net income was also favorably affected bysite, as well as an income tax benefit recorded in the first quarter of 2016 at Ameren (parent) pursuant to the adoption of new accounting guidance related to share-based compensation and increased Ameren Illinois natural gas distribution rates due to seasonal rate redesign. Additionally, in the second quarter of 2016, earnings were favorably affected by increased demand due to warmer early summer temperatures.compensation. Net income was unfavorably affected in the ~~second~~third quarter and the first ~~six~~nine months of 2016, compared with the year-ago periods, by ~~the cost of the Callaway energy center’s scheduled refueling and maintenance outage,~~ decreased electric demand at Ameren Missouri resulting from a reduction in ~~Noranda~~ sales ~~volumes,~~to the New Madrid Smelter, decreased Ameren Missouri earnings resulting from the absence in 2016 of MEEIA 2013 net shared benefits, and ~~decreased electric margins resulting from the exclusion of transmission revenues~~increased depreciation and ~~substantially all transmission charges from~~amortization expenses, primarily at Ameren ~~Missouri’s FAC.~~Missouri. Additionally, earnings were unfavorably affected in the first ~~six~~nine months of 2016, compared to the year-ago period, by ~~decreased demand primarily due to milder winter temperatures~~the cost of the Callaway energy center’s scheduled refueling and maintenance outage, the absence in 2016 of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider ~~mechanism.~~mechanism, and decreased Ameren Missouri electric margins resulting from increased transmission charges, net of transmission revenues. Net income was also unfavorably affected in the third quarter of 2016, compared to the year-ago period, by decreased Ameren Illinois natural gas distribution earnings due to seasonal rate redesign.

Ameren remains focused on executing its strategy of investing in and operating its utilities in a manner consistent with existing regulatory frameworks, enhancing those frameworks and advocating for responsible energy policies, as well as creating and capitalizing on investment opportunities ~~for investment~~ for the benefit of its customers and shareholders. Ameren continues to allocate significant amounts of capital to those businesses that are supported by regulatory frameworks that provide predictable and timely cost recovery. Ameren invested approximately ~~$650 million~~$1 billion of its $1$1.5 billion in capital expenditures during the first ~~six~~nine months of 2016 in FERC-regulated electric transmission projects and Ameren Illinois electric and natural gas distribution service infrastructure. Consistent with its strategic plan, one of Ameren’s goals is to earn at or close to the allowed return on common equity in each of its jurisdictions. Ameren remains focused on improving operating performance, disciplined cost management, and strategic capital allocation.

Ameren invested approximately ~~$330~~$510 million during the first ~~six~~nine months of 2016 in FERC-regulated transmission projects, including Ameren Illinois’ continued significant transmission investments to improve reliability. Construction continues on ATXI’s $1.4 billion Illinois Rivers and $150 million Spoon River transmission ~~project, and ATXI anticipates line construction~~projects. Pre-construction steps continue to ~~begin~~be made on the ~~Spoon River project in late 2016.~~$225 million Mark Twain project. In October 2016, ATXI isfiled suit in the ~~process~~circuit courts of ~~obtaining assents from~~each of the five counties where the Mark Twain project will be ~~constructed.~~constructed to obtain assents for road crossings. A decision from each of the county circuit courts is expected in 2017. ATXI plans to complete the project in 2018; however, delays in obtaining the assents could delay the completion date. The completion of the Illinois Rivers, Spoon River, and Mark Twain transmission projects ~~are expected to~~will provide customers with improved reliability and access to additional renewable energy sources, including wind power from the western and northern parts of the MISO ~~region.~~region, including northeast Missouri.

~~With respect to~~In September 2016, the ~~FERC-regulated electric transmission businesses, Ameren and Ameren Illinois transmission earnings continued to be reduced by~~FERC issued a final order in the ~~recognition of a liability for a potential refund to customers based on the pending FERC~~November 2013 complaint ~~cases regarding~~case which lowered the allowed base return on common ~~equity.~~equity to 10.32%. The new allowed base return on common equity is reflected in rates prospectively from the September 2016 effective date of the order. The FERC is expected to issue a final order in the February 2015 complaint case in the second quarter of ~~2017, which~~2017. The final order in the February 2015 complaint case will determine the allowed base return on common equity for the 15-month period ~~ending~~ended May 2016. The final order in the February 2015 complaint case will also establish the allowed base return on common equity that will apply prospectively from ~~the~~its expected second quarter 2017 effective date, replacing the 10.32% allowed base return on common equity, which became effective in September 2016. The 12.38% allowed base return on common equity was effective for the period that began at the conclusion of the 15-month period for the February 2015 complaint case ~~order, replacing~~in May 2016 through the ~~allowed base return on equity established by~~September 2016 effective date of the final order in the November 2013 complaint ~~case, which is expected to be issued in the fourth quarter of 2016.~~case.

Ameren Illinois has invested approximately ~~$320~~$480 million in electric and natural gas distribution infrastructure projects in the first ~~six~~nine months of ~~2016, including those that are part of its modernization action plan.~~2016. It remains on track to meet its remaining investment, reliability, and smart meter goals under the IEIMA. In April 2016, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update ~~which included~~to establish the

revenue requirement used for 2017 rates. Pending ICC approval, Ameren Illinois’ update filing will result in a ~~$14~~$14 million decrease ~~to its~~in Ameren Illinois’ electric distribution service revenue requirement, beginning in January 2017. ~~In July 2016, the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing. The ICC staff recommended a decrease in the electric~~

distribution service revenue requirement in an amount consistent with Ameren Illinois’ filing. Other intervenors to this rate proceeding have recommended additional decreases to Ameren Illinois’ electric distribution service revenue requirement. An ICC decision on the revenue requirement used for 2017 rates is expected by December 2016.

In July 2016, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $206 million. The request includes recovery of, and a return on, new infrastructure investments, recovery of fixed costs related to the loss of sales to ~~Noranda,~~the New Madrid Smelter, and increased transmission ~~expenses.~~charges. Ameren Missouri also requested continued use of its FAC and the regulatory tracking mechanisms for pension and postretirement benefits and uncertain income tax positions that the MoPSC previously authorized in earlier electric rate orders. Additionally, Ameren Missouri requested the implementation of a new regulatory tracking mechanism for transmission charges and revenues. A decision by the MoPSC is expected by late April 2017, with new rates effective in late May 2017. Ameren Missouri continues to pursue a modernized regulatory framework that supports investment to upgrade aging electric infrastructure and reduces regulatory lag.

In the third quarter of 2016, Ameren Missouri recognized $19 million of revenue related to the MEEIA 2013 performance incentive based on a stipulation agreement between Ameren Missouri and the MoPSC staff, which was filed with the MoPSC in September 2016. In November 2016, the MoPSC approved a $28 million MEEIA 2013 performance incentive based on a revised stipulation agreement between Ameren Missouri, the MoPSC staff, and the MoOPC. As a result, Ameren Missouri will recognize $9 million of additional revenues in the fourth quarter of 2016 relating to the MEEIA 2013 performance incentive. Further, the revised stipulation agreement included a provision to incorporate the results of the appeal, discussed below, regarding the determination of an input used to calculate the performance incentive. In November 2015, the MoPSC issued an order regarding the determination of an input used to calculate the performance incentive. Ameren Missouri filed an appeal of the order with the Missouri Court of Appeals, Western District, which is expected to issue a decision in 2016. If the Missouri Court of Appeals, Western District, overturns the November 2015 MoPSC order, Ameren Missouri may recognize additional revenues in excess of the $28 million approved by the MoPSC in November 2016.

Reflecting confidence in Ameren’s outlook and long-term strategy, in October 2016, Ameren’s board of directors increased the quarterly common stock dividend to 44 cents per share, resulting in an annualized equivalent dividend rate of $1.76 per share.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Weather, economic conditions, energy efficiency investments by our customers and us, and the actions of key customers can significantly affect the demand for our services.

Our results are also affected by seasonal fluctuations in winter heating and summer cooling demands. Ameren and Ameren Missouri are also affected by nuclear refueling and other energy center maintenance outages. Additionally, fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing and our pension and postretirement benefits costs. Almost all 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. Our results of operations, financial position, and liquidity are affected by our ability to align our overall spending, both operating and capital, with regulatory frameworks established by our regulators.

Ameren Missouri principally uses coal, nuclear fuel, and natural gas for fuel in its electric operations and purchases natural gas for its customers. Ameren Illinois purchases power and natural gas for its customers. The prices for these commodities can fluctuate significantly because of the global economic and political environment, weather, supply, and demand, and many other factors. We have natural gas cost recovery mechanisms for our Illinois and Missouri natural gas distribution service businesses, a purchased power cost recovery mechanism for Ameren Illinois' electric distribution service business, and a FAC for Ameren Missouri's electric utility business.

Ameren Illinois' electric distribution 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 included in customer rates for that year, with recoveries from, or refunds to,

customers made in a subsequent year. Included in Ameren Illinois' revenue requirement reconciliation is a formula for the return on equity, which is equal to the average of the monthly yields of 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois' annual return on equity is directly correlated to yields on United States Treasury bonds. Ameren Illinois and ATXI use a company-specific, forward-looking rate formula framework in setting their transmission rates. These ~~forward-looking~~ rates are updated each January with forecasted information. A reconciliation during the year, which adjusts for the actual revenue requirement and actual sales volumes, is used to adjust billing rates in a subsequent year.

Ameren Illinois’ and ATXI’s electric transmission service businesses and Ameren Illinois’ electric distribution service

business operate under formula ratemaking, designed to provide for the recovery of actual costs of service that are prudently incurred as well as a return on equity. While rate-regulated, Ameren Illinois’ natural gas business and Ameren Missouri do not operate under formula ratemaking. Ameren (parent) is not rate-regulated.

We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of Ameren Missouri's energy centers and our 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 manage in order 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 ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Three Months				Six Months				Three Months				Nine Months
	2016		2015		2016		2015		2016		2015		2016		2015
Net income attributable to Ameren common shareholders	$	147	$	150	$	252	$	258	$	369	$	343	$	621	$	601
Earnings per common share – basic and diluted	0.61		0.61		1.04		1.06
Earnings per common share – diluted									1.52		1.41		2.56		2.47
Net income attributable to Ameren common shareholders – continuing operations	$	147	$	98	$	252	$	206	$	369	$	343	$	621	$	549
Earnings per common share – basic and diluted – continuing operations	0.61		0.40		1.04		0.85
Earnings per common share – diluted – continuing operations									1.52		1.41		2.56		2.26

Net income attributable to Ameren common shareholders from continuing operations increased ~~$49~~$26 million, or 2111 cents per diluted share, in the ~~second~~third quarter of 2016 compared with the same period in 2015. The increase between periods was due to a ~~$31 million increase in net income from the Ameren Missouri segment, a $14~~$21 million increase in net income from the Ameren Illinois segment, ~~and~~ a $4$3 million increase in net income from Ameren (parent) and nonregistrant subsidiaries, which included an increase in ATXI’s net income of ~~$7 million.~~$8 million, and a $2 million increase in net income from the Ameren Missouri segment.

Net income attributable to Ameren common shareholders from continuing operations increased ~~$46~~$72 million, or 1930 cents per diluted share, in the first ~~six~~nine months of 2016 compared to the same period in 2015. The increase between periods was due to a ~~$22~~$41 million increase in net income from the Ameren Illinois segment, a $25 million increase in net income from continuing

operations at Ameren (parent) and nonregistrant subsidiaries, which included an increase in ATXI’s net income of ~~$12 million, a~~ $20 million, ~~increase in net income from the Ameren Illinois segment,~~ and a $4$6 million increase in net income from the Ameren Missouri segment.

~~Net~~There was no net income attributable to Ameren common shareholders from discontinued operations ~~was less than $1 million~~ in both the ~~second~~third quarter and the first ~~six~~nine months of 2016, compared with no net income ofand $52 million, ~~or 21 cents per diluted share,~~respectively, in ~~both~~the year-ago periods. During the second quarter of 2015, based on the completion of the IRS audit ~~of Ameren’s~~for 2013, ~~tax year,~~ Ameren removed ~~the~~a previously recorded reserve for unrecognized tax benefits of $53 million ~~recorded in 2013~~ related to the divestiture of New AER and recognized a tax benefit from discontinued operations.

Earnings per share from continuing operations were favorably affected in the ~~second~~third quarter and the first ~~six~~nine months of 2016, compared with the year-ago periods (except where a specific period is referenced), by:

the absence of a provision recognized in the second quarter of 2015 as a result of Ameren Missouri’s discontinued efforts to license and build a second nuclear unit at its existing Callaway energy center site (18 cents per share for ~~both periods)~~the nine months ended September 30, 2016);

increased Ameren Illinois and ATXI electric transmission service and Ameren Illinois electric distribution service earnings under formula ratemaking due to additional rate base investment (7 cents per share and 1216 cents per share, respectively). ~~However, increased~~Additionally, Ameren Illinois and ATXI electric transmission service third quarter earnings ~~due to additional rate base investment were reduced by the recognition of~~benefited from a ~~liability for a potential refund to customers based on the pending FERC complaint cases regarding the~~temporarily higher allowed base return on common equity, recognizing an allowed base return on common equity of 12.38% from mid-May, as a result of the expiration of the refund period in the February 2015 complaint case, to nearly the end of September. This earnings increase was partially offset by a lower allowed base return on common equity recognized through mid-May 2016 in the nine month period as well as a lower return on equity related to Ameren Illinois electric distribution service investments due to a reduction in the 30-year United States Treasury bond yields (1(2 cents per share and 1 cent per share, respectively);

increased demand due to warmer summer temperatures in 2016, partially offset by milder winter temperatures (estimated at 11 cents per share and 29 cents per share, respectively);

higher natural gas distribution rates at Ameren Illinois pursuant to a December 2015 order (3 cents per share and 9 cents per share, respectively);

a decrease in the effective tax rate primarily due to an income tax benefit recorded at Ameren (parent) pursuant to the adoption of new accounting guidance related to share-based compensation (8(7 cents per share for the ~~six~~nine months ended ~~June~~September 30, 2016);

~~increased demand due to warmer early summer temperatures in 2016 (estimated at 7 cents per share for the second quarter of 2016);~~

~~higher natural gas distribution rates at Ameren Illinois pursuant to a December 2015 order (2 cents per share and 6 cents per share, respectively)~~;

decreased other operations and maintenance expenses not subject to riders, regulatory tracking mechanisms, or formula ratemaking, primarily at Ameren Missouri (4(2 cents per share and 35 cents per share, respectively). This was due, in part, to a reduction in energy center maintenance costs, excluding the cost of the Callaway energy center's scheduled refueling and maintenance outage (discussed below); and reduced electric distribution maintenance expenditures; and

~~increased Ameren Illinois natural gas distribution rates due to seasonal rate redesign, which is not expected to materially affect earnings comparisons on an annual basis (2~~the recognition of a MEEIA 2013 performance incentive (5 cents per share for ~~the six months ended June 30, 2016)~~both periods).

Earnings per share from continuing operations were unfavorably affected in the ~~second~~third quarter and the first ~~six~~nine months of 2016, compared with the year-ago periods (except where a specific period is referenced), by:

the cost of the Callaway energy center's scheduled refueling and maintenance outage in the second quarter of 2016. There was no Callaway refueling and maintenance outage in 2015 (7 cents per share and 8 cents per share, respectively);

~~a decrease in~~decreased electric demand at Ameren Missouri resulting from a reduction in ~~Noranda~~ sales ~~volumes~~to the New Madrid Smelter (5 cents per share and 813 cents per share, respectively);

decreased Ameren Missouri earnings resulting from the absence in 2016 of MEEIA net shared benefits due to the expiration of MEEIA 2013 (4(5 cents per share and 712 cents per share, respectively);

~~decreased demand primarily due to milder winter temperatures, partially offset by warmer early summer temperatures (discussed above) (estimated at 2~~the cost of the Callaway energy center's scheduled refueling and maintenance outage in the second quarter of 2016. There was no Callaway refueling and maintenance outage in 2015 (8 cents per share for the ~~six~~nine months ended ~~June~~September 30, 2016);

decreased Ameren Illinois earnings resulting from the absence in 2016 of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism (4 cents per share for the ~~six~~nine months ended ~~June~~September 30, 2016); ~~and~~

decreased Ameren Missouri electric margins resulting from ~~the exclusion~~increased transmission charges, net of transmission revenues (3 cents per share for the nine months ended September 30, 2016);

increased depreciation and ~~substantially all transmission charges from~~amortization expenses not subject to riders, regulatory tracking mechanisms, or formula ratemaking, primarily because of electric system capital additions at Ameren ~~Missouri’s FAC beginning May 30, 2015~~Missouri (2 cents per share and 3 cents per share, respectively); and

decreased Ameren Illinois natural gas distribution earnings due to seasonal rate redesign, which is not expected to materially affect earnings comparisons on an annual basis (2 cents per share for the three months ended September 30, 2016).

The cents per share information presented in the explanations above is based on the average diluted shares outstanding in the ~~second~~third quarter and first ~~six~~nine months of 2015. For additional details regarding the Ameren Companies’ results of operations, including explanations of Margins, Other Operations and Maintenance Expenses, Provision for Callaway Construction and Operating License, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income and Expenses, Interest Charges, and Income Taxes, see the major headings below.

Below is a table of income statement components by segment for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Ameren Missouri			Ameren Illinois			Other / Intersegment Eliminations			Ameren			Ameren Missouri			Ameren Illinois			Other / Intersegment Eliminations			Ameren
Three Months 2016:
Electric margins	$	628		$	321		$	24		$	973		$	862		$	452		$	28		$	1,342
Natural gas margins	17			96			(1		)	112			14			86			—			100
Other revenues													1			—			(1		)	—
Other operations and maintenance	(238		)	(200		)	3			(435		)	(220		)	(198		)	7			(411		)
Depreciation and amortization	(127		)	(80		)	(3		)	(210		)	(130		)	(80		)	(1		)	(211		)
Taxes other than income taxes	(83		)	(30		)	(2		)	(115		)	(96		)	(30		)	(3		)	(129		)
Other income	7			3			—			10
Other income (expense)													12			1			(3		)	10
Interest charges	(53		)	(35		)	(7		)	(95		)	(53		)	(35		)	(9		)	(97		)
Income taxes	(58		)	(29		)	(5		)	(92		)	(148		)	(77		)	(8		)	(233		)
Income from continuing operations	93			46			9			148			242			119			10			371
Income from discontinued operations, net of tax	—			—			—			—			—			—			—			—
Net income	93			46			9			148			242			119			10			371
Noncontrolling interests – preferred dividends	(1		)	(1		)	1			(1		)	(1		)	—			(1		)	(2		)
Net income attributable to Ameren common shareholders	$	92		$	45		$	10		$	147		$	241		$	119		$	9		$	369
Three Months 2015:
Electric margins	$	635		$	299		$	10		$	944		$	863		$	412		$	13		$	1,288
Natural gas margins	17			88			—			105			14			82			(1		)	95
Other revenues	1			—			(1		)	—			1			—			(1		)	—
Other operations and maintenance	(229		)	(202		)	4			(427		)	(233		)	(202		)	7			(428		)
Provision for Callaway construction and operating license	(69		)	—			—			(69		)
Depreciation and amortization	(124		)	(73		)	(3		)	(200		)	(125		)	(74		)	(2		)	(201		)
Taxes other than income taxes	(85		)	(29		)	(2		)	(116		)	(97		)	(29		)	(2		)	(128		)
Other income													11			1			2			14
Interest charges													(54		)	(33		)	—			(87		)
Income taxes													(140		)	(59		)	(9		)	(208		)
Income from continuing operations													240			98			7			345
Income from discontinued operations, net of tax													—			—			—			—
Net income													240			98			7			345
Noncontrolling interests – preferred dividends													(1		)	—			(1		)	(2		)
Net income attributable to Ameren common shareholders													$	239		$	98		$	6		$	343


	Ameren Missouri			Ameren Illinois			Other / Intersegment Eliminations			Ameren			Ameren Missouri			Ameren Illinois			Other / Intersegment Eliminations			Ameren
Other income (expense)	10			2			(2		)	10
Interest charges	(55		)	(33		)	(1		)	(89		)
Income taxes	(39		)	(20		)	—			(59		)
Income from continuing operations	62			32			5			99
Income from discontinued operations, net of tax	—			—			52			52
Net income	62			32			57			151
Noncontrolling interests – preferred dividends	(1		)	(1		)	1			(1		)
Net income attributable to Ameren common shareholders	$	61		$	31		$	58		$	150
Six Months 2016:
Nine Months 2016:
Electric margins	$	1,077		$	609		$	48		$	1,734		$	1,939		$	1,061		$	76		$	3,076
Natural gas margins	43			250			(1		)	292			57			336			(1		)	392
Other revenues													1			—			(1		)	—
Other operations and maintenance	(450		)	(394		)	9			(835		)	(670		)	(592		)	16			(1,246		)
Depreciation and amortization	(254		)	(157		)	(6		)	(417		)	(384		)	(237		)	(7		)	(628		)
Taxes other than income taxes	(156		)	(68		)	(5		)	(229		)	(252		)	(98		)	(8		)	(358		)
Other income	20			3			—			23
Other income (expense)													32			4			(3		)	33
Interest charges	(105		)	(70		)	(15		)	(190		)	(158		)	(105		)	(24		)	(287		)
Income (taxes) benefit	(67		)	(67		)	11			(123		)	(215		)	(144		)	3			(356		)
Income from continuing operations	108			106			41			255			350			225			51			626
Income from discontinued operations, net of tax	—			—			—			—			—			—			—			—
Net income	108			106			41			255			350			225			51			626
Noncontrolling interests – preferred dividends	(2		)	(2		)	1			(3		)	(3		)	(2		)	—			(5		)
Net income attributable to Ameren common stockholders	$	106		$	104		$	42		$	252
Six Months 2015:
Net income attributable to Ameren common shareholders													$	347		$	223		$	51		$	621
Nine Months 2015:
Electric margins	$	1,132		$	587		$	23		$	1,742		$	1,995		$	999		$	36		$	3,030
Natural gas margins	44			238			—			282			58			320			(1		)	377
Other revenues	1			—			(1		)	—			2			—			(2		)	—
Other operations and maintenance	(440		)	(404		)	16			(828		)	(673		)	(606		)	23			(1,256		)
Provision for Callaway construction and operating license	(69		)	—			—			(69		)	(69		)	—			—			(69		)
Depreciation and amortization	(242		)	(146		)	(5		)	(393		)	(367		)	(220		)	(7		)	(594		)
Taxes other than income taxes	(165		)	(72		)	(4		)	(241		)	(262		)	(101		)	(6		)	(369		)
Other income (expense)	18			4			(4		)	18			29			5			(2		)	32
Interest charges	(110		)	(66		)	(1		)	(177		)	(164		)	(99		)	(1		)	(264		)
Income taxes	(65		)	(55		)	(5		)	(125		)	(205		)	(114		)	(14		)	(333		)
Income from continuing operations	104			86			19			209			344			184			26			554
Income from discontinued operations, net of tax	—			—			52			52			—			—			52			52
Net income	104			86			71			261			344			184			78			606
Noncontrolling interests – preferred dividends	(2		)	(2		)	1			(3		)	(3		)	(2		)	—			(5		)
Net income attributable to Ameren common stockholders	$	102		$	84		$	72		$	258
Net income attributable to Ameren common shareholders													$	341		$	182		$	78		$	601

Margins

The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in the three and ~~six~~nine months ended ~~June~~September 30, 2016, compared with the year-ago periods. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as gas revenues less gas purchased for resale. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP and may not be comparable to other companies' presentations or more useful than the GAAP information we provide elsewhere in this report.

Three Months
Ameren
Missouri

Ameren
Illinois

Other^(a)
Ameren
Electric revenue change:
Effect of weather (estimate)^(b)
$ 26
$ 5
$ —
$ 31
Base rates (estimate) 19
3
—
22
Sales volume (excluding Noranda and the estimated effect of weather) 2
(1 ) —
1
Noranda revenues (35 ) —
—
(35 )
Off-system sales and transmission services revenues 21
—
—
21
MEEIA 2013 net shared benefits (15 ) —
—
(15 )
Transmission services revenues —
17
12
29
Other 4
1
2
7
Cost recovery mechanisms – offset in fuel and purchased power:^(c)

Power supply costs —
2
—
2
Recovery of FAC under-recovery (28 ) —
—
(28 )
Other cost recovery mechanisms:^(d)

Bad debt, energy efficiency programs, and environmental remediation cost riders —
(2 ) —
(2 )
MEEIA 2013 and 2016 program costs (9 ) —
—
(9 )
Total electric revenue change $ (15 ) $ 25
$ 14
$ 24
Fuel and purchased power change:
Energy costs $ (19 ) $ —
$ —
$ (19 )
Noranda energy costs 17
—
—
17
Effect of weather (estimate)^(b)
(4 ) (1 ) —
(5 )
Effect of higher net energy costs included in base rates (10 ) —
—
(10 )
FAC exclusion of transmission services charges^(e)
(6 ) —
—
(6 )
Other 2
—
—
2
Cost recovery mechanisms – offsets in electric revenue:^(c)

Power supply costs —
(2 ) —
(2 )
Recovery of FAC under-recovery 28
—
—
28
Total fuel and purchased power change $ 8
$ (3 ) $ —
$ 5
Net change in electric margins $ (7 ) $ 22
$ 14
$ 29
Natural gas revenue change:
Effect of weather (estimate)^(b)
$ 1
$ 3
$ —
$ 4
Base rates (estimate) —
11
—
11
Seasonal rate redesign —
(3 ) —
(3 )
Other 1
(1 ) (1 ) (1 )
Cost recovery mechanism – offset in gas purchased for resale:^(c)

Purchased gas costs (2 ) (6 ) —
(8 )
Other cost recovery mechanisms:^(d)

Bad debt, energy efficiency programs, and environmental remediation cost riders —
(1 ) —
(1 )
Gross receipts tax (1 ) 1
—
—
Total natural gas revenue change $ (1 ) $ 4
$ (1 ) $ 2
Gas purchased for resale change:
Effect of weather (estimate)^(b)
$ (1 ) $ (2 ) $ —
$ (3 )
Cost recovery mechanism – offset in natural gas revenue:^(c)

Purchased gas costs 2
6
—
8
Total gas purchased for resale change $ 1
$ 4
$ —
$ 5
Net change in natural gas margins $ —
$ 8
$ (1 ) $ 7



Three Months	Ameren Missouri			Ameren Illinois			Other^(a)			Ameren
Electric revenue change:
Effect of weather (estimate)^(b)	$	41		$	14		$	—		$	55
Base rates (estimate)	—			8			—			8
Sales volume (excluding the New Madrid Smelter and the estimated effect of weather)	—			6			—			6
New Madrid Smelter revenues	(42		)	—			—			(42		)
Off-system sales	50			—			—			50
MEEIA 2013 net shared benefits	(19		)	—			—			(19		)
MEEIA 2013 performance incentive	19			—			—			19
Transmission services revenues	1			18			16			35
Other	(11		)	(8		)	(6		)	(25		)
Cost recovery mechanisms – offset in fuel and purchased power:^(c)
Power supply costs	—			(25		)	—			(25		)
Transmission services recovery mechanism	—			3			—			3
Recovery of FAC under-recovery	(39		)	—			—			(39		)
Other cost recovery mechanisms:^(d)
Bad debt, energy efficiency programs, and environmental remediation cost riders	—			6			—			6
MEEIA 2013 and 2016 program costs	(7		)	—			—			(7		)
Total electric revenue change	$	(7	)	$	22		$	10		$	25
Fuel and purchased power change:
Energy costs (excluding the New Madrid Smelter and estimated effect of weather)	$	(48	)	$	—		$	—		$	(48	)
New Madrid Smelter energy costs	22			—			—			22
Effect of weather (estimate)^(b)	(7		)	(6		)	—			(13		)
Transmission services charges	(3		)	—			—			(3		)
Other	3			2			5			10
Cost recovery mechanisms – offsets in electric revenue:^(c)
Power supply costs	—			25			—			25
Transmission services recovery mechanism	—			(3		)	—			(3		)
Recovery of FAC under-recovery	39			—			—			39
Total fuel and purchased power change	$	6		$	18		$	5		$	29
Net change in electric margins	$	(1	)	$	40		$	15		$	54
Natural gas revenue change:
Effect of weather (estimate)^(b)	$	—		$	1		$	—		$	1
Base rates (estimate)	—			9			—			9
Seasonal rate redesign	—			(6		)	—			(6		)
Other	—			(1		)	1			—
Cost recovery mechanism – offset in gas purchased for resale:^(c)
Purchased gas costs	1			(6		)	—			(5		)
Other cost recovery mechanisms:^(d)
Bad debt, energy efficiency programs, and environmental remediation cost riders	—			2			—			2
Total natural gas revenue change	$	1		$	(1	)	$	1		$	1
Gas purchased for resale change:
Effect of weather (estimate)^(b)	$	—		$	(1	)	$	—		$	(1	)
Cost recovery mechanism – offset in natural gas revenue:^(c)
Purchased gas costs	(1		)	6			—			5
Total gas purchased for resale change	$	(1	)	$	5		$	—		$	4
Net change in natural gas margins	$	—		$	4		$	1		$	5


Six Months	Ameren Missouri			Ameren Illinois				Other^(a)			Ameren
Nine Months														Ameren Missouri			Ameren Illinois			Other^(a)			Ameren
Electric revenue change:
Effect of weather (estimate)^(b)	$	(8	)	$	(5	)		$	—		$	(13	)	$	33		$	9		$	—		$	42
Base rates (estimate)	48			22				—			70			48			30			—			78
Sales volume (excluding Noranda and the estimated effect of weather)	3			(7		)		—			(4		)
Noranda revenues	(59		)	—				—			(59		)
Off-system sales and transmission services revenues	35			—				—			35
Sales volume (excluding the New Madrid Smelter and the estimated effect of weather)														3			(1		)	—			2
New Madrid Smelter revenues														(101		)	—			—			(101		)
Off-system sales														85			—			—			85
MEEIA 2013 net shared benefits	(26		)	—				—			(26		)	(45		)	—			—			(45		)
MEEIA 2013 performance incentive														19			—			—			19
Transmission services revenues	—			24				24			48			1			42			40			83
Purchased power rider order in 2015	—			(15		)		—			(15		)	—			(15		)	—			(15		)
Other	10			4				(5		)	9			(1		)	(4		)	(11		)	(16		)
Cost recovery mechanisms – offset in fuel and purchased power:^(c)
Power supply costs	—			10				—			10			—			(15		)	—			(15		)
Transmission services recovery mechanism																	3			—			3
Recovery of FAC under-recovery	(49		)	—				—			(49		)	(88		)	—			—			(88		)
Other cost recovery mechanisms:^(d)														—
Bad debt, energy efficiency programs, and environmental remediation cost riders	—			(6		)		—			(6		)
Gross receipts tax	(4		)	—				—			(4		)	(4		)	—			—			(4		)
MEEIA 2013 and 2016 program costs	(13		)	—				—			(13		)	(20		)	—			—			(20		)
Total electric revenue change	$	(63	)	$	27			$	19		$	(17	)	$	(70	)	$	49		$	29		$	8
Fuel and purchased power change:
Energy costs	$	(29	)	$	—			$	—		$	(29	)
Noranda energy costs	28			—				—			28
Energy costs (excluding the New Madrid Smelter and estimated effect of weather)														$	(77	)	$	—		$	—		$	(77	)
New Madrid Smelter energy costs														50			—			—			50
Effect of weather (estimate)^(b)	5			4			��	—			9			(2		)	(2		)	—			(4		)
Effect of higher net energy costs included in base rates	(34		)	—				—			(34		)	(34		)	—			—			(34		)
FAC exclusion of transmission services charges^(e)	(11		)	—				—			(11		)
Transmission services charges														(14		)	—			—			(14		)
Other	—			1				6			7			3			3			11			17
Cost recovery mechanisms – offsets in electric revenue:^(c)
Power supply costs	—			(10		)		—			(10		)	—			15			—			15
Transmission services recovery mechanism														—			(3		)	—			(3		)
Recovery of FAC under-recovery	49			—				—			49			88			—			—			88
Total fuel and purchased power change	$	8		$	(5	)		$	6		$	9		$	14		$	13		$	11		$	38
Net change in electric margins	$	(55	)	$	22			$	25		$	(8	)	$	(56	)	$	62		$	40		$	46
Natural gas revenue change:
Effect of weather (estimate)^(b)	$	(8	)	$	(26	)		$	—		$	(34	)	$	(8	)	$	(25	)	$	—		$	(33	)
Base rates (estimate)	—			25				—			25			—			34			—			34
Seasonal rate redesign	—			6				—			6
Other	1			(1		)		(1		)	(1		)	1			(2		)	—			(1		)
Cost recovery mechanism – offset in gas purchased for resale:^(c)
Purchased gas costs	(4		)	(55		)		—			(59		)	(3		)	(61		)	—			(64		)
Other cost recovery mechanisms:^(d)
Bad debt, energy efficiency programs, and environmental remediation cost riders	—			(13		)		—			(13		)	—			(11		)	—			(11		)
Gross receipts tax	(1		)	(2		)		—			(3		)	(1		)	(2		)	—			(3		)
Total natural gas revenue change	$	(12	)	$	(66	)		$	(1	)	$	(79	)	$	(11	)	$	(67	)	$	—		$	(78	)
Gas purchased for resale change:
Effect of weather (estimate)^(b)	$	7		$	23			$	—		$	30		$	7		$	22		$	—		$	29
Cost recovery mechanism – offset in natural gas revenue:^(c)
Purchased gas costs	4			55				—			59			3			61			—			64
Total gas purchased for resale change	$	11		$	78			$	—		$	89		$	10		$	83		$	—		$	93
Net change in natural gas margins	$	(1	)	$	12			$	(1	)	$	10		$	(1	)	$	16		$	—		$	15


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


(b)	Represents the estimated variation resulting primarily from changes in cooling and heating degree-days on electric and natural gas demand compared with the prior-year period; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories.


(c)	Electric and natural gas revenue changes are offset by corresponding changes in Fuel, Purchased power, and Gas purchased for resale, resulting in no change to electric and natural gas margins.


(d)	See Other Operations and Maintenance Expenses or Taxes Other Than Income Taxes in this section for the related offsetting increase or decrease to expense. These items have no overall impact on earnings.


~~(e)~~	~~Amounts are subsequent to May 30, 2015, due to the exclusion of transmission revenues and substantially all transmission charges from the FAC as a result of the April 2015 MoPSC electric rate order.~~

Ameren Corporation

Ameren's electric margins increased ~~$29~~$54 million, or 3%4%, and $46 million, or 2%, for the three and nine months ended ~~June~~September 30, 2016, respectively, compared with the year-ago ~~period. However, electric margins decreased $8 million, or less than 1%, for the six months ended June 30, 2016, compared with the year-ago period.~~periods. Ameren's natural gas margins increased $7$5 million, or 7%5%, and ~~$10~~$15 million, or 4%, for the three and ~~six~~nine months ended ~~June~~September 30, 2016, respectively, compared with the year-ago periods. Ameren’s results were primarily driven by Ameren Missouri’s, Ameren Illinois’, and ATXI’s results of operations, as discussed below. ATXI’s transmission services revenues increased ~~$12~~$16 million and ~~$24~~$40 million for the three and ~~six~~nine months ended ~~June~~September 30, 2016, respectively, compared with the year-ago periods, because of higher rate base investment and recoverable costs under ~~forward-looking~~ formula ~~ratemaking reduced by~~ratemaking. ATXI’s results for the ~~recognition of~~three months ended September 30, 2016, also benefited from a ~~potential refund to customers based on the pending FERC complaint cases regarding the~~temporarily higher allowed ~~base~~ return on common ~~equity.~~equity, compared with the year-ago period, reflecting the May expiration of the 15-month refund period for the February 2015 complaint case. See Note 2 -– Rate and Regulatory Matters under Part I,1, Item 1, of this report for information regarding the ~~FERC complaint cases.~~allowed return on common equity for FERC-regulated transmission rate base.

Ameren Missouri

Ameren Missouri has a FAC cost recovery mechanism that allows it to recover or refund, through customer rates, 95% of changes in net energy costs greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudence reviews, with the remaining 5% of changes absorbed by Ameren Missouri.

Net energy costs, as defined in the FAC, include fuel and purchased power costs, including transportation, net of off-system sales. As of May 30, 2015, transmission revenues and substantially all transmission charges are excluded from net energy costs as a result of the April 2015 MoPSC electric rate order, which unfavorably affected margins as discussed below. 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 through customer rates does not affect Ameren Missouri’s electric margins, as any change in revenue is offset by a corresponding change in fuel expense to reduce the previously recognized FAC regulatory asset.

Ameren Missouri's electric margins for the three months ended September 30, 2016 were comparable with the year-ago period, and decreased $7$56 million, or ~~1%, and $55 million, or 5%~~3%, for the ~~three and six~~nine months ended ~~June~~September 30, 2016, ~~respectively,~~ compared with the year-ago ~~periods.~~period. The following items had an unfavorable effect on Ameren Missouri's electric margins for the three and ~~six~~nine months ended ~~June~~September 30, 2016, compared with the year-ago ~~periods (except where a specific period is referenced):~~periods:

~~Noranda’s~~The New Madrid Smelter operations were ~~idled~~suspended in the first quarter of 2016, which decreased margins by ~~$18~~$20 million and ~~$31~~$51 million, respectively. The change in margins due to lower ~~Noranda~~New Madrid Smelter sales is the sum of ~~Noranda~~New Madrid Smelter revenues (-$3542 million and -$59101 million, respectively) and ~~Noranda~~New Madrid Smelter energy costs (+$1722 million and +$2850 million, respectively) in the above table. ~~Noranda~~

New Madrid Smelter energy costs include the impact of a provision in the FAC tariff that, under certain circumstances, allows

Ameren Missouri to retain a portion of the revenues from any off-system sales it makes as a result of reduced ~~tariff~~ sales to ~~Noranda.~~the New Madrid Smelter. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding ~~Noranda.~~the New Madrid Smelter.

The absence in 2016 of net shared benefits due to the expiration of MEEIA 2013, which decreased margins by ~~$15~~$19 million and ~~$26~~$45 million, respectively. Net shared benefits compensated Ameren Missouri for lower sales volumes from energy-efficiency related volume reductions in current and future periods.

~~The exclusion of transmission revenues and substantially all transmission charges from the FAC beginning May 30, 2015, which decreased margins by $6 million and $11 million, respectively.~~ Increased transmission services charges ~~are primarily due to~~resulting from additional MISO-approved electric transmission investments made by other ~~entities.~~

~~Temperatures in the first six months of 2016 were warmer as heating degree-days decreased 18% while cooling degree-days increased 13%, compared with the year-ago period. The net effect of weather~~entities, which decreased margins by ~~an estimated~~ $3 million ~~for the six months ended June 30, 2016, compared with the year-ago period. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-$8 million)~~ and ~~the effect of weather (estimate) on fuel and purchased power (+$5 million) in the above table. See below for the favorable impact of weather on the second quarter of 2016.~~$14 million, respectively.

The following items had a favorable effect on Ameren Missouri's electric margins for the three and ~~six~~nine months ended ~~June~~September 30, 2016, compared with the year-ago periods (except where a specific period is referenced):

~~Early summer~~Summer temperatures for the ~~second~~third quarter of 2016 were warmer as cooling degree-days increased 11%, compared with the year-ago period. Temperatures in the first nine months of 2016 were warmer as cooling degree-days increased 12%, while heating degree-days decreased 17%, compared with the year-ago period. The net effect of weather increased margins by an estimated ~~$22~~$34 million ~~for the second quarter of 2016 compared with the year-ago period.~~and $31 million, respectively. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$~~26 million)~~41 million and +$33 million, respectively) and the effect of weather (estimate) on fuel and purchased power (-$~~4 million)~~7 million and -$2 million, respectively) in the above table.

The MEEIA 2013 performance incentive increased margins by $19 million for both periods. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding the MEEIA 2013 performance incentive.

Higher electric base rates, effective May 30, 2015, as a result of the April 2015 MoPSC electric rate order, ~~which~~ increased margins by an estimated ~~$9 million and~~ $14 million ~~respectively.~~for the nine months ended September 30, 2016. The change in electric base rates is the sum of the change in base rates (estimate) (+$~~19 million and +$~~48 ~~million, respectively)~~million) and the effect of higher net energy costs included in base rates (-$~~10 million and -$~~34 ~~million, respectively)~~million) in the above table.

Lower net energy costs as a result of the 5% of changes absorbed by Ameren Missouri through the FAC, primarily due to higher MISO capacity revenues, which increased margins by $2 million and $6$8 million, respectively. The change in net energy costs is the sum of the change in off-system sales ~~and transmission services revenues~~ (+$2150 million and +$3585 million, respectively) and the change in energy costs (-$1948 million and -$2977 million, respectively) in the above table.

Excluding the effect of reduced sales to the New Madrid Smelter and the estimated effect of weather, ~~and reduced sales to Noranda,~~ total retail sales volumes increased by less than 1% for ~~both periods,~~the nine months

ended September 30, 2016, which increased revenues by ~~$2 million and~~ $3 million, ~~respectively,~~ due to an additional day as a result of the leap year and growth partially offset by the carryover effect of MEEIA 2013 on sales volumes. ~~The six months ended June 30, 2016, benefited from an additional day as a result of the leap year.~~

Ameren Missouri’s natural gas margins were comparable between periods.

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

Ameren ~~Missouri’s natural gas margins were comparable between periods.~~

~~Ameren~~ Illinois

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

The provisions of the IEIMA’s and the FERC’s electric transmission formula rate frameworks provide for annual reconciliations of the electric distribution and electric transmission service revenue requirements necessary to reflect the actual costs incurred in a given year with the revenue requirements in customer rates for that year, including an allowed return on equity. See Operations and Maintenance Expenses in this section for additional information regarding the components of the revenue requirements. In each of those electric jurisdictions, if the current year's revenue requirement is greater than the revenue requirement reflected in that year’s customer rates, 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. In each jurisdiction, if the current year's revenue requirement is less than the revenue requirement reflected in that year’s customer rates, 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. The increases or reductions to electric operating revenues are shown in base rates (estimate) and transmission services revenues, in the above table, for the electric distribution and electric transmission service revenues, respectively. 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 ~~$22~~$40 million, ~~in both periods,~~ or 7%10%, and 4%$62 million, or 6%, for the three and ~~six~~nine months ended ~~June~~September 30, 2016, respectively, compared with the year-ago periods. The following items had a favorable effect on Ameren Illinois’ electric margins for the three and ~~six month periods~~nine months ended ~~June~~September 30, 2016, compared with the year-ago periods (except where a specific period is referenced):

Transmission services revenues increased by ~~$17~~$18 million and ~~$24~~$42 million, respectively, primarily due to increased rate base investment and higher recoverable costs under ~~forward-looking~~ formula

ratemaking. Transmission services for the three months ended September 30, 2016, also benefited from a temporarily higher allowed return on common equity, compared with the year-ago period reflecting the May expiration of the 15-month refund period for the February 2015 complaint case. See Note 2 – Rate and Regulatory Matters under Part 1, Item 1, of this report for information regarding the allowed return on common equity for FERC-regulated transmission rate base.

Electric distribution service revenues increased by an estimated $3$8 million and ~~$22~~$30 million, respectively, primarily due to increased rate base investment and higher recoverable costs under formula ratemaking pursuant to the IEIMA, partially offset by a lower return on equity due to a reduction in the 30-year United States Treasury bond yields.

~~Early summer~~Summer temperatures for the ~~second~~third quarter of 2016 were warmer as cooling degree-days increased 3%13%, compared with the year-ago period. Temperatures in the first nine months of 2016 were warmer as cooling degree-days increased 10%, while heating degree-days decreased 15%, compared with the year-ago period. The net effect of weather increased margins by an estimated $4$8 million ~~for the second quarter of 2016, compared with the year-ago period.~~and $7 million, respectively. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$~~5 million)~~14 million and +$9 million, respectively) and the effect of weather (estimate) on fuel and purchased power (-$~~1 million)~~6 million and -$2 million, respectively) in the above table. ~~See below~~

Excluding the estimated effect of weather, total retail sales volumes increased by 3% for the ~~unfavorable impact of weather in~~three months ended September 30, 2016, primarily due to the ~~first six months of 2016.~~commercial sector, which increased margins by an estimated $6 million.

~~The following items had an unfavorable effect on~~ Ameren Illinois’ electric margins ~~for~~were unfavorably affected by the ~~three and six months ended June 30, 2016, compared with the year-ago periods (except where a specific period is referenced):~~

~~The~~ absence in 2016 of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism, which increased margins by $15 million in the first ~~six~~nine months of 2015.

Excluding the estimated effect of weather, total retail sales volumes decreased 2% for the six months ended June 30, 2016, which decreased margins by an estimated $7 million. Lower retail sales volumes were due to industrial sales volumes that decreased by 3% but have less of a margin impact than residential and commercial sales volumes, which decreased a combined 1%.

Temperatures in the first six months of 2016 were warmer as heating degree-days decreased 15% while cooling degree-days increased 4%, compared with the year-ago period. The net effect of weather decreased margins by an estimated $1 million for the six months ended June 30, 2016, compared with the year-ago period. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-$5 million) and the effect of weather (estimate) on fuel and purchased power (+$4 million) in the above table.

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

Ameren Illinois' natural gas margins increased $8$4 million, or 9%5%, and ~~$12~~$16 million, or 5%, for the three and ~~six~~nine months ended ~~June~~September 30, 2016, respectively, compared with the year-ago periods. ~~The following items had a favorable effect on~~ Ameren Illinois’

natural gas margins ~~for the three and six month periods ended June 30, 2016, compared with the year-ago periods (except where a specific period is referenced):~~

~~Higher~~were favorably affected by higher natural gas base rates in 2016, which increased margins by an estimated ~~$11~~$9 million and ~~$25~~$34 million, respectively.

The implementation of redesigned seasonal rates in 2016, which increased margins by $6 million for the six months ended June 30, 2016, compared with the year-ago period. These redesigned rates have an effect on quarterly earnings comparisons but are not expected to materially affect annual earnings.

The following items had an unfavorable effect on Ameren Illinois’ natural gas margins for the three and ~~six month periods~~nine months ended ~~June~~September 30, 2016, compared with the year-ago periods (except where a specific period is referenced):

The absence of colder-than-normal winter temperatures and the application of the VBA in the first ~~six~~nine months of 2016, which decreased margins by $3 million compared with the year-ago period. The VBA, which was approved by the ICC in December 2015, eliminated the impact of weather on natural gas margins for residential and small nonresidential customers in the first ~~six~~nine months of 2016. The change in

margins due to weather is the sum of the effect of weather (estimate) on natural gas revenues (-$2625 million) and the effect of weather (estimate) on gas purchased for resale (+$2322 million) in the above table.

The implementation of redesigned seasonal rates in 2016, which decreased margins by $3$6 million for the ~~second~~third quarter of 2016, compared with the year-ago period. These redesigned rates have an effect on quarterly earnings comparisons but are not expected to materially affect annual earnings.

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

Other Operations and Maintenance Expenses

Ameren Corporation

Other operations and maintenance expenses ~~increased $8~~decreased $17 million and $7$10 million in the ~~second~~third quarter and the first ~~six~~nine months of 2016, respectively, as compared with the year-ago periods, primarily because of ~~increased~~decreased expenses at Ameren Missouri ~~partially offset by a reduction in expenses at~~and Ameren Illinois.

Ameren Missouri

Other operations and maintenance expenses were $9$13 million and ~~$10~~$3 million ~~higher~~lower in the ~~second~~third quarter and the first ~~six~~nine months of 2016, respectively, as compared with the year-ago periods. The following items increased other operations and maintenance expenses for the three and six months ended June 30, 2016, compared with the year-ago periods (except where a specific period is referenced):

Refueling and maintenance outage costs at the Callaway energy center increased by $27 million and $31 million, respectively, due to costs for the 2016 scheduled refueling and maintenance outage that ended in May. There was no scheduled outage in 2015.

Amortization of previously deferred solar rebate costs increased by $3 million and $10 million, respectively, as a result of the April 2015 MoPSC electric rate order. Electric base rates billed to customers increased electric revenues by a corresponding amount, with no overall effect on net income.

~~Litigation costs increased by $2 million in both periods.~~

The following items decreased other operations and maintenance expenses for the three and ~~six~~nine months ended ~~June~~September 30, 2016, compared with the year-ago periods (except where a specific period is referenced):

MEEIA customer energy efficiency program costs decreased by $9$7 million and ~~$13~~$20 million, respectively, ~~primarily~~ due to the expiration of MEEIA 2013, partially offset by costs incurred for MEEIA 2016. Electric revenues decreased by a corresponding amount, with no overall effect on net income.

Energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center, decreased by $8$6 million and ~~$12~~$18 million, respectively, primarily due to fewer major ~~outages.~~outages, partially offset by higher coal handling charges.

Electric distribution maintenance expenditures decreased by $7 million and $12 million, respectively, primarily related to reduced system repair and vegetation management work.

Employee benefit costs decreased by ~~$4 million and~~ $7 million ~~respectively,~~in the nine months ended September 30, 2016, primarily due to a change in pension and postretirement expenses allowed in rates, as a result of the April 2015 MoPSC electric rate order. Electric base rates billed to customers decreased electric revenues by a corresponding amount, with no overall effect on net income.

An unrealized MTM gain in 2016 compared with an unrealized MTM loss in 2015, resulting from changes in the

market value of company-owned life insurance investments, decreased expense by $6 million in both periods.

The following items increased other operations and maintenance expenses for the three and nine months ended September 30, 2016, compared with the year-ago periods (except where a specific period is referenced):

Refueling and maintenance outage costs at the Callaway energy center increased by $31 million in the nine months ended September 30, 2016, due to costs for the scheduled refueling and maintenance outage that occurred in the second quarter of 2016. There was no scheduled outage in 2015.

Amortization of previously deferred solar rebate costs increased by $10 million in the nine months ended September 30, 2016, as a result of the April 2015 MoPSC electric rate order. Electric base rates billed to customers increased electric revenues by a corresponding amount, with no overall effect on net income.

Litigation costs increased by $8 million and $10 million, respectively, primarily related to increases in estimated obligations for pending legal claims.

Storm-related repair costs increased by $4 million and $7 million, respectively.

Ameren Illinois

Pursuant to the provisions of the IEIMA’s and the FERC’s formula rate frameworks, recoverable electric service costs that are not recovered through separate cost recovery mechanisms are included in Ameren Illinois’ revenue requirement reconciliations, which result in corresponding adjustments to electric revenues, with no overall effect on net income. These recoverable electric 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 $2$4 million and ~~$10~~$14 million lower in the ~~second~~third quarter and the first ~~six~~nine months of 2016, respectively, as compared with the year-ago periods. The following items decreased other operations and maintenance expenses for the three and ~~six~~nine months ended ~~June~~September 30, 2016, compared with the year-ago periods (except where a specific period is referenced):

Employee benefit costs decreased by $5 million and $12 million, respectively, primarily due to lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.

Bad debt, customer energy efficiency, and environmental remediation costs decreased by $3$11 million ~~and $19 million, respectively.~~in the nine months ended September 30, 2016. These expenses are included in cost riders that result in lower electric and natural gas revenues, with no overall effect on net income.

Employee benefit costs decreased by $2 million and $7 million, respectively, primarily due to lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.

Electric distribution and transmission maintenance expenditures decreased by $2$7 million ~~in the second quarter of 2016,~~and $5 million, respectively, primarily related to the timing of system repair work and reduced circuit maintenance work.

An unrealized MTM gain in 2016 compared with an unrealized MTM loss in 2015, resulting from changes in the market value of company-owned life insurance investments, decreased expense by $4 million in both periods.

The following items increased other operations and maintenance expenses for the three and ~~six~~nine months ended ~~June~~September 30, 2016, compared with the year-ago periods (except where a specific period is referenced):

Labor costs, other than those incorporated into other explanations presented, increased by $1$3 million and $4$7 million, respectively, primarily because of staff additions to meet enhanced ~~reliability~~ standards and ~~customer service~~ goals related to the IEIMA.

~~Litigation costs increased by $3 million in both periods.~~

Storm-related repair costs increased by $3$4 million in the ~~six~~nine months ended ~~June~~September 30, 2016.

~~Electric distribution and transmission maintenance expenditures~~Litigation costs increased by $2 million in the ~~six~~nine months ended ~~June~~September 30, ~~2016, primarily related to~~2016.

Bad debt, customer energy efficiency, and environmental remediation costs increased by $8 million in the ~~timing~~third quarter of ~~system repair~~2016. These expenses are included in cost riders that result in higher electric and ~~vegetation management work.~~natural gas revenues, with no overall effect on net income.

Provision for Callaway Construction and Operating License

Primarily because of changes in vendor support for licensing efforts at the NRC, Ameren Missouri’s assessment of long-term capacity needs, declining costs of alternative generation technologies, and the regulatory framework in Missouri, Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway energy center site in the second quarter of 2015. As a result of this decision, Ameren and Ameren Missouri recognized a $69 million noncash pretax provision for all of the previously capitalized COL costs.

Depreciation and Amortization

Ameren Corporation

Depreciation and amortization expenses increased $10 million and ~~$24~~$34 million in the ~~second~~third quarter and the first ~~six~~nine months of 2016, respectively, as compared with the year-ago periods, ~~primarily~~ because of increased expenses at Ameren Missouri and Ameren Illinois, as discussed below.

Ameren Missouri

Depreciation and amortization expenses increased ~~$3 million and $12~~$5 million in the ~~second~~third quarter of 2016, primarily because of electric system capital additions. Depreciation and amortization expenses increased $17 million in the first ~~six~~nine months of 2016, ~~respectively,~~ primarily because of increased depreciation rates resulting from the April 2015 MoPSC electric rate order and electric system capital additions.

Ameren Illinois

Depreciation and amortization expenses increased $7$6 million and ~~$11~~$17 million in the ~~second~~third quarter and the first ~~six~~nine months of 2016, respectively, primarily because of electric system capital additions.

Taxes Other Than Income Taxes

Ameren Corporation

Taxes other than income taxes were comparable in the ~~second~~third quarter of 2016 with the year-ago period. Taxes other than income taxes decreased ~~$12~~$11 million in the first ~~six~~nine months of 2016, as compared with the year-ago period, primarily because of decreased expenses at Ameren Missouri and Ameren Illinois, as discussed below. See Excise Taxes in Note 1 – Summary of Significant Accounting Policies under Part I, Item 1, of this report for additional information.

Ameren Missouri

Taxes other than income taxes ~~decreased $2 million~~were comparable in the ~~second~~third quarter of 2016 primarily because of decreased property taxes resulting from lower assessed property values and decreased gross receipts taxes resulting from lower electric sales volumes, partially offset by a decrease in capitalized property taxes.with the year-ago period. Taxes other than income taxes decreased $9$10 million in the first ~~six~~nine months of 2016, primarily because of decreased gross receipts taxes resulting from lower electric sales and natural gas volumes ~~an increase in capitalized property taxes,~~ and decreased property taxes resulting from lower assessed property values. Electric revenues for gross receipts taxes decreased by an amount corresponding to the reduction in gross receipts taxes, with no overall effect on net income.

Ameren Illinois

Taxes other than income taxes were comparable in the ~~second~~third quarter of 2016 with the ~~second quarter of 2015.~~year-ago period. Taxes other than income taxes decreased $4$3 million in the first ~~six~~nine months of 2016, primarily because of decreased gross receipts taxes, resulting from lower natural gas sales volumes and ~~prices.~~prices, and because of a decrease in property taxes between periods. Natural gas revenues for gross receipts taxes decreased by an amount corresponding to the reduction in gross receipts taxes, with no overall effect on net income.

Other Income and Expenses

~~Ameren Corporation~~

~~Other income, net~~Details of ~~expenses, was comparable in the second quarterof 2016 with the year-ago period. Other income, net of expenses, increased $5 million in the first six months of 2016~~, ~~as compared with the year-ago period, primarily because of a $3 million reduction in donations at Ameren (parent) due to the timing of charitable contributions and an increase in~~ other income ~~net of~~and expenses atfor the Ameren ~~Missouri, as discussed below. See~~Companies are provided in 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 $3 million in the second quarter of 2016, primarily because of a decrease in the allowance for equity funds used during construction resulting from the increased use of short-term debt to fund capital

expenditures. Other income, net of expenses, increased $2 million in the first six months of 2016, primarily because of an increase in the allowance for equity funds used during construction, resulting from higher capital expenditures, and a decrease in donations.

~~Ameren Illinois~~

~~Other income, net of expenses, was comparable in both the second quarter and the first six months of 2016 with the year-ago periods.~~report.

Interest Charges

Ameren Corporation

Interest charges increased $6$10 million and ~~$13~~$23 million in the ~~second~~third quarter and the first ~~six~~nine months of 2016, respectively, as compared with the year-ago periods, due to an approximately $500 million increase in average outstanding debt and an increase in the cost of debt at Ameren (parent). Ameren (parent) issued senior unsecured notes in November 2015 to repay lower-cost short-term ~~debt incurred primarily in connection with the funding of increasing ATXI capital expenditures.~~debt. A decrease in interest charges in ~~both periods~~the first nine months of 2016 at Ameren Missouri was partially offset by an increase in interest charges in both periods at Ameren Illinois,

as discussed below.

Ameren Missouri

Interest charges were comparable in the third quarter of 2016 with the year-ago period. Interest charges decreased ~~$2 million and $5~~$6 million in the ~~second quarter and the~~ first ~~six~~nine months of 2016, ~~respectively,~~ primarily because of a decrease in ~~the~~ average outstanding debt.

Ameren Illinois

Interest charges were comparable in the third quarter of 2016 with the year-ago period. Interest charges increased ~~$2 million and $4~~$6 million in the ~~second quarter and the~~ first ~~six~~nine months of 2016, ~~respectively,~~ primarily because of an increase in average outstanding ~~debt.~~debt and interest on refunds for the November 2013 and February 2015 complaint cases. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information about the complaint cases.

Income Taxes

The following table presents effective income tax rates for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Three Months^(a)				Six Months^(a)				Three Months^(a)				Nine Months^(a)
	2016		2015		2016		2015		2016		2015		2016		2015
Ameren	38	%	37	%	33	%	37	%	39	%	38	%	36	%	38	%
Ameren Missouri	38	%	39	%	38	%	38	%	38	%	37	%	38	%	37	%
Ameren Illinois	39	%	38	%	39	%	39	%	39	%	38	%	39	%	38	%


(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 comparable in the ~~second~~third quarter of 2016 with the year-ago period.

The effective tax rate was lower in the first ~~six~~nine months of 2016, as compared with the year-ago period, primarily because of the recognition of excess tax benefits associated with share-based compensation resulting from the difference between the deduction for tax purposes and the compensation cost recognized for financial reporting purposes. See Accounting and Reporting Developments in Note 1 – Summary of Significant Accounting Policies under Part I, Item 1, of this report for additional information.

Ameren Missouri

The effective tax rate was comparable in the ~~second~~third quarter and the first ~~six~~nine months of 2016 with the year-ago periods.

Ameren Illinois

The effective tax rate was comparable in the ~~second~~third quarter and the first ~~six~~nine months of 2016 with the year-ago periods.

LIQUIDITY AND CAPITAL RESOURCES

Our tariff-based gross margins are our principal source of cash from operating activities. A diversified retail customer mix, primarily consisting of rate-regulated residential, commercial, and industrial customers, provides us with a reasonably predictable source of cash. In addition to using cash generated from operating activities, we use available cash, credit agreement borrowings, commercial paper issuances, ~~money pool borrowings,~~ or, in the case of Ameren Missouri and Ameren Illinois, money pool borrowings and other short-term borrowings from affiliates to support normal operations and temporary capital requirements. We may reduce our short-term borrowings with cash from operations, long-term borrowings, or, in the case of Ameren Missouri and Ameren Illinois, capital contributions from Ameren (parent). We expect to make significant capital expenditures over the next five years as we invest in our electric and natural gas utility infrastructure to support overall system reliability, environmental compliance, and other improvements. We intend to fund those capital expenditures with available cash on hand, cash generated from operating activities, ~~and~~ commercial paper borrowings and debt issuances so that we maintain an equity ratio around 50%, assuming constructive regulatory environments.

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 ~~June~~September 30, 2016, for ~~the~~ Ameren ~~Companies.~~and Ameren Illinois. The working capital deficit as of ~~June~~September 30, 2016, was primarily the result of current maturities of long-term debt and our decision to finance our businesses with ~~more low-cost~~lower-cost commercial paper ~~issuances.~~issuances and money pool borrowings. With the credit capacity available under the Credit Agreements and our cash and cash equivalents, the Ameren Companies had access to ~~$1.3~~$1.5 billion of liquidity at ~~June~~September 30, 2016.

The following table presents net cash provided by (used in) operating, investing, and financing activities for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Net Cash Provided By (Used In) Operating Activities									Net Cash Used In Investing Activities									Net Cash Provided by (Used In) Financing Activities									Net Cash Provided By (Used In) Operating Activities								Net Cash Used In Investing Activities									Net Cash Provided by (Used In) Financing Activities
	2016			2015			Variance			2016			2015			Variance			2016			2015			Variance			2016		2015			Variance			2016			2015			Variance			2016			2015			Variance
Ameren^(a) – continuing operations	$	765		$	782		$	(17	)	$	(1,035	)	$	(875	)	$	(160	)	$	(7	)	$	91		$	(98	)	$	1,559	$	1,547		$	12		$	(1,551	)	$	(1,362	)	$	(189	)	$	(282	)	$	(113	)	$	(169	)
Ameren^(a) – discontinued operations	(2		)	(1		)	(1		)	—			—			—			—			—			—			—		(5		)	5			—			—			—			—			—			—
Ameren Missouri	364			446			(82		)	(354		)	(328		)	(26		)	(209		)	(119		)	(90		)	888		1,040			(152		)	(724		)	(739		)	15			(362		)	(233		)	(129		)
Ameren Illinois	382			386			(4		)	(438		)	(375		)	(63		)	(15		)	(12		)	(3		)	627		541			86			(679		)	(615		)	(64		)	(16		)	73			(89		)


(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 $17~~increased $12 million in the first ~~six~~nine months of 2016, compared with the same period in 2015. The following items contributed to the ~~decrease:~~increase:

~~A $36 million increase in payments to purchase stock associated with share-based compensation plan awards.~~

~~A $30 million decrease resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.~~

~~A $27 million increase in the cost of natural gas held in storage caused primarily by fewer withdrawals as a result of milder winter temperatures compared with the prior year.~~

~~A $26 million increase in payments for nuclear refueling and maintenance outages at the Ameren Missouri Callaway energy center. There was no refueling and maintenance outage in 2015.~~

A $13 million increase in interest payments, primarily due to an increase in the average outstanding debt, including Ameren (parent) senior unsecured notes and Ameren Illinois senior secured notes issued during the fourth quarter of 2015.

~~An $11 million increase in storm restoration costs.~~

~~A $10 million decrease in net energy costs collected from Ameren Missouri customers under the FAC.~~

~~A $5 million increase in property tax payments at Ameren Missouri caused by higher assessed property tax values.~~

~~The following items partially offset the decrease in Ameren's cash from operating activities associated with continuing operations between periods:~~

A $42 million insurance receipt at Ameren Missouri related to the Taum Sauk breach. See Note 15 – Commitments and Contingencies under Part II, Item 8, in the Form 10-K for additional information.

A ~~$21 million decrease in the cost of coal inventory at Ameren Missouri, as additional coal was purchased in 2015 to compensate for delivery disruptions experienced in 2014.~~

~~A $19 million decrease in expenditures for customer energy efficiency programs compared with amounts collected from Ameren Illinois customers.~~

~~An $18~~$32 million increase in cash associated with the recovery of Ameren Illinois' IEIMA revenue requirement reconciliation adjustments. The 2014 revenue requirement reconciliation adjustment, which is being recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.

A ~~$14~~$30 million decrease in ~~pension and postretirement benefit plan contributions caused by a change~~coal inventory at Ameren Missouri, as additional coal was purchased in ~~actuarial assumptions.~~2015 to compensate for delivery disruptions experienced in 2014.

A $25 million decrease in payments for purchased power compared with amounts collected from Ameren Illinois customers.

A $17 million decrease in expenditures for customer energy efficiency programs compared with amounts collected from Ameren Illinois customers.

A $15 million increase in cash associated with Ameren Illinois' transmission revenue requirement reconciliation adjustments, as $7 million was collected from customers in 2016 comparedto $8 million refunded to customers in 2015.

Income tax refunds of $6$7 million in 2016, compared with income tax payments of $3$6 million in 2015. In 2016, Ameren generated net operating losses due to bonus depreciation, resulting in no current federal income tax liability.

A $9net $8 million decrease in collateral postings with counterparties, primarily at Ameren Missouri, resulting from changes in the market prices of power and natural gas and in contracted commodity volumes.

The following items partially offset the increase in Ameren's cash from operating activities associated with continuing operations between periods:

A $54 million decrease in net energy costs collected from Ameren Missouri customers under the FAC.

A $36 million increase in ~~cash~~payments to purchase stock associated with share-based compensation plan awards.

A $26 million increase in payments for the nuclear refueling and maintenance outage at the Ameren ~~Illinois' transmission revenue requirement reconciliation adjustments,~~Missouri Callaway energy center. There was no refueling and maintenance outage in 2015.

An $18 million increase in the cost of natural gas held in storage caused primarily by fewer withdrawals as a result of milder winter temperatures compared with the prior year.

A $16 million increase in interest payments, primarily due to an increase in the cost of Ameren (parent) debt, and an increase in the average outstanding debt at Ameren Illinois.

A $12 million decrease resulting from the change in customer receivable balances, partially offset by an increase in electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items.

A $4 million ~~was collected from customers~~increase in ~~2016 comparedto $5 million refunded to customers in 2015.~~

storm restoration costs.

Ameren’s cash from operating activities associated with discontinued operations was ~~comparable between periods.~~immaterial in both 2016 and 2015.

Ameren Missouri

Ameren Missouri’s cash from operating activities decreased ~~$82~~$152 million in the first ~~six~~nine months of 2016, compared with the same period in 2015. The following items contributed to the decrease:

A ~~$60~~$104 million decrease resulting from a reduction in electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.

Income tax payments of $4$11 million to Ameren (parent) pursuant to the tax allocation agreement in 2016, compared with income tax refunds of ~~$47~~$52 million in 2015 primarily related to an audit settlement.

A $54 million decrease in net energy costs collected from customers under the FAC.

A $26 million increase in payments for nuclear refueling and maintenance ~~outages~~outage at the Callaway energy center. There was no refueling and maintenance outage in 2015.

~~A $10 million decrease in net energy costs collected from customers under the FAC.~~

~~A $6 million increase in the cost of natural gas held in storage caused primarily by fewer withdrawals as a result of milder winter temperatures compared with the prior year.~~

~~A $5 million increase in property tax payments caused by higher assessed property tax values.~~

The following items partially offset the decrease in Ameren Missouri’s cash from operating activities between periods:

A $42 million insurance receipt related to the Taum Sauk breach. See Note 15 – Commitments and Contingencies under Part II, Item 8, in the Form 10-K for additional information.

A ~~$21~~$30 million decrease in ~~the cost of~~ coal inventory, as additional coal was purchased in 2015 to compensate for delivery disruptions experienced in 2014.

A net $5 million decrease in collateral postings with counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes.

A $4 million decrease in pension and postretirement benefit plan contributions caused by a change in actuarial assumptions.

Ameren Illinois

Ameren Illinois’ cash from operating activities ~~decreased $4~~increased $86 million in the first ~~six~~nine months of 2016, compared with the same period in 2015. The following items contributed to the ~~decrease:~~increase:

A ~~$21~~$53 million increase ~~in the cost of natural gas held in storage caused primarily by fewer withdrawals as a result of milder winter temperatures compared with the prior year.~~

Income tax payments of $11 million to Ameren (parent) pursuant to the tax allocation agreement in 2016, compared with income tax refunds of $5 million in 2015, primarily related to an audit settlement.

~~An $8 million increase in storm restoration costs.~~

~~A $6 million increase in interest payments, primarily due to~~resulting from an increase in ~~the average outstanding debt, including senior secured notes issued~~electric and natural gas margins, as discussed in ~~December 2015.~~

~~The following~~Results of Operations, excluding certain noncash items, partially offset by the ~~decrease~~change in ~~Ameren Illinois’ cash from operating activities between periods:~~customer receivable balances.

A ~~$19 million decrease in expenditures for customer energy efficiency programs compared with amounts collected from customers.~~

~~An $18~~$32 million increase in cash associated with the recovery of IEIMA revenue requirement reconciliation adjustments. The 2014 revenue requirement reconciliation adjustment, which is being recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.

A $25 million decrease in payments for purchased power compared with amounts collected from customers.

A $17 million decrease in expenditures for customer energy efficiency programs compared with amounts collected from customers.

A $9$15 million increase in cash associated with transmission revenue requirement reconciliation adjustments, as $4$7 million was collected from customers in 2016 compared to $5$8 million refunded to customers in 2015.

The following items partially offset the increase in Ameren Illinois’ cash from operating activities between periods:

A $4$14 million ~~decrease~~increase in the cost of natural gas held in storage caused primarily by fewer withdrawals as a result of milder winter temperatures compared with the prior year.

An $8 million increase in interest payments, primarily due to an increase in the average outstanding debt, including senior secured notes issued in December 2015.

A $7 million increase in pension and postretirement benefit plan contributions caused by ~~a change~~the timing of payments.

A $4 million increase in ~~actuarial assumptions.~~storm restoration costs.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities associated with continuing operations increased ~~$160~~$189 million in the first ~~six~~nine months of 2016, compared with the same period in 2015. Capital

expenditures increased $~~154~~164 million principally as a result of the

activity at ~~Ameren Missouri and~~ Ameren Illinois, as discussed below, and a ~~$25~~$43 million increase in ATXI’s capital expenditures, which primarily related to the Illinois Rivers and Spoon River projects.

Ameren Missouri’s cash used in investing activities ~~increased $26~~decreased $15 million in the first ~~six~~nine months of 2016, compared with the same period in 2015, due in part to an $85 million decrease in net money pool advances. These items were partially offset by increased capital expenditures of ~~$64~~$56 million primarily related to electric distribution system reliability and energy center projects ~~partially offset by a return of $36~~as well as an $11 million increase in ~~money pool advances.~~nuclear fuel expenditures.

Ameren Illinois’ cash used in investing activities increased ~~$63~~$64 million due to an increase in capital expenditures primarily related to qualified investments in natural gas infrastructure under the QIP rider, smart meter investments made pursuant to IEIMA, and storm restoration costs.

Ameren Missouri continually reviews its 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 changes. 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, changes in laws or regulations, and our ability and willingness to pursue transmission investments, among other factors. Any changes in future generation, transmission, or distribution needs could result in significant capital expenditures or impairment losses, which could be material. 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.

Cash Flows from Financing Activities

Cash provided by, or used in, financing activities is ~~driven by~~a result of our financing needs, which depend on the level of cash provided by operating activities, the level of cash used in investing activities, the dividends declared by Ameren’s board of directors, and our long-term debt maturities, among other things.

Ameren’s cash used in financing activities associated with continuing operations ~~used net cash of $7~~increased $169 million during the first ~~six~~nine months of 2016, compared to ~~providing net cash of $91 million during~~ the same period in 2015. Short-term and long-term debt issuances, net of long-term debt repayments, resulted in ~~$70~~$137 million less cash provided by financing activities in the first ~~six~~nine months of 2016, compared with the year-ago period. Additionally, there was a $20 million increase in employee withholding taxes related to share-based payments in the first nine months of 2016, compared to the same period in 2015.

Ameren Missouri’s cash used in financing activities increased ~~$90~~$129 million in the first ~~six~~nine months of 2016, compared with the same period in 2015. Cash used in net short-term and

long-term debt activity was ~~$34~~$111 million in 2016, compared with providing cash of ~~$76~~$38 million in the year-ago period. Cash paid to Ameren (parent) as dividends, net of capital contributions received from parent, decreased $19 ~~million.~~million between the two nine-month periods.

Ameren Illinois’ ~~cash used in~~ financing activities ~~increased $3~~used net cash of $16 million induring the first ~~six~~nine months of 2016, compared ~~with~~to providing net cash of $73 million during the same period in 2015. ~~Cash~~

Ameren Illinois paid Ameren (parent) dividends of $95 million, compared with no dividend payments in 2015. Additionally, cash provided by net short-term and long-term debt activity, ~~was $48~~as well as money pool borrowings, increased $7 million in 2016, compared with ~~cash used in net short-term debt and money pool borrowings of $10 million in~~ the year-ago period. ~~Additionally, in 2016, Ameren Illinois paid~~

~~Ameren (parent) dividends of $60 million, compared with no dividend payments in 2015.~~

See Long-term Debt and Equity in this section for additional information on maturities and issuances of long-term debt.

Credit Facility Borrowings and Liquidity

The liquidity needs of Ameren, Ameren Missouri, and Ameren Illinois are typically supported through the use of available cash, commercial paper issuances, short-term intercompany borrowings, or drawings under committed credit ~~agreements, or commercial paper issuances.~~agreements. 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 Ameren’s consolidated liquidity as of ~~June~~September 30, 2016:


Ameren and Ameren Missouri:
Missouri Credit Agreement – borrowing capacity ^(a)	$	1,000
Missouri Credit Agreement (a) – borrowing capacity			$	1,000
Less: Ameren (parent) commercial paper outstanding	306		263
Less: Ameren Missouri commercial paper outstanding	77		—
Missouri Credit Agreement – credit available	617		737
Ameren and Ameren Illinois:
Illinois Credit Agreement – borrowing capacity ^(a)	1,100
Illinois Credit Agreement (a) – borrowing capacity			1,100
Less: Ameren (parent) commercial paper outstanding	218		188
Less: Ameren Illinois commercial paper outstanding	177		157
Less: Letters of credit	4		4
Illinois Credit Agreement – credit available	701		751
Total Credit Available	$	1,318	$	1,488
Cash and cash equivalents	13		18
Total Liquidity	$	1,331	$	1,506


(a)	Expires in December 2019.

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

In addition, Ameren Missouri and Ameren Illinois may borrow cash from the utility money pool when funds are available. The

rate of interest depends on the composition of internal and

external funds in the utility money pool. Ameren Missouri and Ameren Illinois ~~borrow~~will access funds from the utility money pool, ~~when funds are available before utilizing~~ the Credit Agreements, ~~and~~or the commercial paper programs ~~because~~depending on which option has the ~~utility money pool~~lowest interest ~~rates are lower.~~rates.

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by the FERC under the Federal Power Act. In February 2016, the FERC issued an order authorizing Ameren Missouri to issue up to $1 billion of short-term debt securities through March 2018. In ~~July~~August 2016, the FERC issued an order authorizing Ameren Illinois ~~filed a request for a two-year extension of its~~to issue up to $1 billion of short-term debt ~~issuance authority, which is set to expire in~~securities through September ~~2016.~~2018.

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), maturities, and redemptions of long-term debt for the Ameren Companies for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015. The Ameren Companies did not issue any common stock during the first ~~six~~nine months of 2016 or 2015. In March 2016 and 2015, Ameren Missouri received cash capital contributions of $38 million and $224 million, respectively, from Ameren (parent).



	Month Issued, Redeemed, or Matured	2016		2015
Issuances of Long-term Debt
Ameren Missouri:
3.65% Senior secured notes due 2045	June	$	149	$	—
3.65% Senior secured notes due 2045	April	—		249
Total Ameren long-term debt issuances		$	149	$	249
Redemptions and Maturities of Long-term Debt
Ameren Missouri:
5.40% Senior secured notes due 2016	February	$	260	$	—
4.75% Senior secured notes due 2015	April	—		114
Ameren Illinois:
6.20% Senior secured notes due 2016	June	54		—
6.25% Senior secured notes due 2016	June	75		—
Total Ameren long-term debt redemptions and maturities		$	389	$	114

The Ameren Companies may sell securities registered under their effective registration statements if market conditions and capital requirements warrant such sales. Any offer and sale will be made only by means of a prospectus that meets the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

Indebtedness Provisions and Other Covenants

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

At ~~June~~September 30, 2016, the Ameren Companies were in compliance with the provisions and covenants contained ~~within~~in 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 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

The amount and timing of Ameren’s common stock dividends are within the sole discretion of Ameren’s board of directors. Ameren’s 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 14, 2016, Ameren’s board of

directors declared a quarterly common stock dividend of 44 cents per share payable on December 30, 2016, to shareholders of record on December 7, 2016, resulting in an annualized equivalent dividend rate of $1.76 per share. The previous annualized equivalent dividend rate, based on the common stock dividend declared and paid in the third quarter of 2016, was $1.70 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 ~~June~~September 30, 2016, none of these circumstances existed at Ameren, Ameren Missouri, or Ameren Illinois and, as a result, these companies were not restricted from paying dividends.

The following table presents common stock dividends declared and paid by Ameren Corporation to its common shareholders and by Ameren Missouri and Ameren Illinois to their parent, Ameren Corporation, for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:

Six Months
2016 2015
Ameren Missouri $ 210
$ 415
Ameren Illinois 60
—
Ameren 206
199



	Nine Months
	2016		2015
Ameren Missouri	$	285	$	490
Ameren Illinois	95		—
Ameren	309		298

Contractual Obligations

For a 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 ~~June~~September 30, 2016, total obligations related to commitments for coal, natural gas, nuclear fuel, purchased power, methane gas, equipment, and meter reading services, among other agreements, at Ameren, Ameren Missouri, and Ameren Illinois were ~~$4,465~~$4,328 million, ~~$2,614~~$2,428 million, and ~~$1,790~~$1,859 million, respectively.

Off-Balance-Sheet Arrangements

Credit Ratings

The credit ratings of the Ameren Companies assigned by Moody’s and S&P can affect our liquidity, access to the capital markets and credit markets, cost of borrowing under credit facilities and commercial paper programs, and collateral posting requirements under commodity contracts.

The following table presents the principal credit ratings of the Ameren Companies by Moody’s and S&P effective on the date of this report:



	Moody’s	S&P
Ameren:
Issuer/corporate credit rating	Baa1	BBB+
Senior unsecured debt	Baa1	BBB
Commercial paper	P-2	A-2
Ameren Missouri:
Issuer/corporate credit rating	Baa1	BBB+
Secured debt	A2	A
Senior unsecured debt	Baa1	BBB+
Commercial paper	P-2	A-2
Ameren Illinois:
Issuer/corporate credit rating	A3	BBB+
Secured debt	A1	A
Senior unsecured debt	A3	BBB+
Commercial paper	P-2	A-2

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 change in~~weakening of our credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing, resulting in an adverse effect on earnings. Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial at Ameren, Ameren Missouri, and Ameren Illinois at ~~June~~September 30, 2016. ~~Sub-investment-grade~~A sub-investment-grade issuer or senior unsecured debt rating (whether below “BBB-“” from S&P or below “Baa3” from Moody’s) at ~~June~~September 30, 2016, 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 ~~$107~~$106 million, ~~$66~~$60 million, and ~~$41~~$46 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at ~~June~~September 30, 2016, if market prices were 15% higher or lower than ~~June~~September 30, 2016 levels in the next 12 months and 20% higher or lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois ~~would only~~could be required to post an immaterial amount, compared to each company’s liquidity, of collateral or other assurances for certain trade ~~obligations that would be immaterial compared to each company’s liquidity.~~obligations.

OUTLOOK

We seek to earn competitive returns on investments in our businesses. We are seeking to improve our regulatory frameworks and cost recovery mechanisms and simultaneously pursuing constructive regulatory outcomes within existing frameworks. We are seeking to align our overall spending, both operating and capital, with economic conditions and with regulatory frameworks established by our regulators. Consequently, we are focused on minimizing the gap between allowed and earned returns on equity. We intend to allocate capital resources to our 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 our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 2016 and beyond.

Operations

Our strategy for earning competitive returns on our 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 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 transmission line from western Indiana across the state of Illinois to eastern Missouri. The last section of this project is expected to be completed by 2019. The Spoon River project located in northwest Illinois and the Mark Twain project located in northeast Missouri are the other two MISO-approved projects to be constructed by ATXI. These two projects are expected to be completed in 2018. The Illinois Rivers and the Spoon River projects have received all of the necessary commission approvals to authorize their construction. In April 2016, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. ~~Starting~~Before starting construction, ~~under the certificate is subject to~~ ATXI ~~obtaining~~must obtain assents for road crossings from the five counties where the line will be constructed. None of the five county commissions approved ATXI’s requests for the assents. In October 2016, ATXI filed suit in each of the five county circuit courts to obtain the assents. A decision from each of the county circuit courts is expected in 2017. ~~Extended difficulties~~ATXI is planning to complete the project in 2018; however, delays in obtaining the assents could delay the completion date. The total investment in all three projects is expected to be more than $1.0 billion from 2016 through 2019. This total includes over $60 million of investment by Ameren Illinois to construct connections to its existing transmission system. In addition to its investment in the MISO-approved projects, Ameren Illinois expects to invest $1.9 billion in electric transmission assets from 2016 through 2020 to address load growth and reliability requirements.

Both Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. With the rates that ~~became~~will become effective on January 1, ~~2016,~~2017, and the currently allowed ~~12.38%~~10.82% return on common equity, which includes a 50 basis point incentive adder, the

~~2016~~ 2017 revenue requirement for Ameren Illinois’ electric transmission business would be ~~$241~~$258 million, which represents a ~~$42~~$17 million increase over the ~~2015~~2016 revenue requirement, which was based on a 12.38% return on common equity, primarily due to rate base growth. These rates reflect a capital structure ~~composed~~comprised of ~~51.9%~~51.6% common equity and a projected average rate base of ~~$1.2~~$1.4 billion. With the rates that ~~became~~will become effective on January 1, ~~2016,~~2017, and the currently allowed ~~12.38%~~10.82% return on equity, which includes a 50 basis point incentive adder, the ~~2016~~2017 revenue requirement for ATXI’s electric transmission business would be ~~$140~~$171 million, which represents a ~~$60~~$31 million increase over the ~~2015~~2016 revenue requirement, which was based on a 12.38% return on common equity, primarily due to rate base growth ~~primarily~~ as a result of the Illinois Rivers project. These rates reflect a capital structure ~~composed~~comprised of ~~56.1%~~56.2% common equity and a projected average rate base of ~~$0.9~~$1.1 billion.

The ~~12.38%~~ return on common equity iswas the subject of two FERC complaint proceedings, the November 2013 complaint case and the February 2015 complaint case, that each challenge the allowed base return on common equity for MISO transmission owners. In ~~December 2015,~~September 2016, the FERC issued a ~~FERC administrative law judge issued an initial decision~~final order in the November 2013 complaint case ~~that would lower~~which lowered the allowed base return on common equity to 10.32%. The order was consistent with the initial decision an administrative law judge issued in December 2015 and ~~would require~~requires customer refunds, with interest, to be issued for the 15-month period ~~ending~~ended February 2015. ~~The FERC is expected to issue a final order in~~In addition, the ~~November 2013 complaint case in the fourth quarter of 2016, which will determine the~~new allowed base return on common equity ~~for~~is reflected in rates prospectively from the 15-month period ending February 2015. The final order in the November 2013 complaint case will also establish a new allowed base return on equity that will replace the current allowed base return on common equity of 12.38% for the period between theSeptember 2016 effective date of the ~~November 2013 complaint case order and~~order.Refunds are expected to be issued in the ~~effective date~~first half of ~~the allowed base return on common equity established by the February 2015 complaint case, as discussed below.~~2017. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case ~~that~~which would lower the allowed base return on common equity to 9.70% and would require customer refunds, with interest, to be issued for the 15-month period ~~ending~~ended May 2016. The FERC is expected to issue a final order in the February 2015 complaint case in the second quarter of ~~2017, which~~2017. The final order in the February 2015 complaint case will determine the allowed base return on common equity for the 15-month period ~~ending~~ended May 2016. The final order in the February 2015 complaint case will also establish the allowed base return on common equity that will apply prospectively from ~~the~~its expected second quarter 2017 effective date, ofreplacing the ~~February 2015 complaint case order, replacing the~~10.32% allowed base return on common equity, ~~established by the November 2013 complaint case.~~which became effective in September 2016. A 50 basis point reduction in the FERC-allowed base return on common equity would reduce Ameren's and Ameren Illinois' ~~annual earnings~~net income by an estimated $6$7 million and $3$4 million, respectively, based on each company’s ~~2016~~2017 projected average rate base. Ameren and Ameren Illinois recorded current regulatory liabilities on their respective ~~June~~September 30, 2016 balance sheets, representing their ~~estimate of the potential refunds.~~

~~In January 2015, a FERC-approved incentive adder of up to 50 basis points on the allowed base return on common equity for our participation in an RTO became effective.~~

~~Upon the issuance~~estimate of the final order addressing the November 2013 complaint case, beginning with its January 2015 effective date, the incentive adder will reduce any refund to customers relating to a reduction of the allowed base return on common equity from the complaint cases discussed above.expected refunds.

On July 1, 2016, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $206 million. The electric rate increase request is based on a 9.9% return on equity, a capital structure ~~composed~~comprised of 51.8% equity, a rate base of $7.2 billion, and a test year ended March 31, 2016, with certain pro-forma adjustments ~~expected~~ through the anticipated true-up date of December 31, 2016. As a part of its filing, Ameren Missouri requested the amortization over ten years of an estimated $81 million of lost fixed cost recovery due to lower sales, ~~volumes,~~ as discussed below, ~~from Noranda~~to the New Madrid Smelter during the period April 2015 through May 2017. The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by late April 2017 and new rates effective in late May 2017. A 50 basis point change in Ameren Missouri’s return on common equity would result in an estimated $18 million change in Ameren’s and Ameren Missouri’s net income, based on Ameren Missouri’s current electric rate base.

In April 2015, the MoPSC issued an order approving an increase in Ameren Missouri’s annual revenues for electric service. The order also approved Ameren Missouri’s request for continued use of the FAC; however, it changed the FAC to exclude all transmission revenues and substantially all transmission charges. This change to Ameren Missouri’s FAC is contributing to regulatory lag. For example, the April 2015 MoPSC electric rate order included $29 million of transmission charges in base rates that were previously included in the FAC. Ameren Missouri expects transmission charges to increase to ~~$53~~$50 million in 2016, with further cost increases expected in the foreseeable future. However, transmission revenues included in base rates in the April 2015 MoPSC electric rate order totaled $34 million and are expected to remain relatively constant in 2016 and into the near future. In its July 2016 electric rate case, in an effort to mitigate the regulatory lag resulting from the changes to the FAC in the April 2015 order, Ameren Missouri requested the implementation of a new tracking mechanism for transmission charges and revenues.

Ameren Missouri supplies electricity to ~~Noranda’s aluminum smelter located in southeast Missouri. In its April 2015 electric rate order,~~ the MoPSC approved a rate design that established $78 million in annual revenues, net of fuel and purchased power costs, as Noranda’s portion of Ameren Missouri’s revenue requirement. The portion of Ameren Missouri’s annual revenue requirement reflected in Noranda’s electric rate is based on the smelter using approximately 4.2 million megawatthours annually, which is almost 100% of its operating capacity.New Madrid Smelter. In the first quarter of 2016, ~~Noranda idled production~~operations at ~~its aluminum smelter.~~the New Madrid Smelter were suspended. In addition, Noranda filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the

United States Bankruptcy Code. In October 2016, Noranda sold the New Madrid Smelter to ARG International AG. As a result of these events in 2016, actual sales volumes to ~~Noranda~~the New Madrid Smelter will be significantly below the sales volumes reflected in rates and, therefore, Ameren Missouri has not fully recovered and will not fully recover its revenue requirement, which included $78 million for sales to the New Madrid Smelter, until rates are adjusted prospectively by the MoPSC in the July 2016 electric rate case to accurately reflect ~~Noranda’s~~the smelter’s actual sales volumes. Ameren Missouri estimates a $38 million reduction in 2016 earnings, compared to 2015, relating to the significantly lower expected electric sales ~~volumes~~ to ~~Noranda~~the New Madrid Smelter after

consideration of the FAC-tariff provision that allows Ameren Missouri to retain a portion of its off-system sales. In the first five months of 2017, Ameren Missouri estimates an $8 million reduction in earnings related to the continuation of significantly lower expected electric sales to the New Madrid Smelter. However, the expected adjustment of rates in May 2017 to accurately reflect the smelter’s actual sales volumes is estimated to result in a $30 million increase in 2017 earnings, compared to 2016 earnings. Operations at the New Madrid Smelter remain suspended and Ameren Missouri is uncertain of future sales to the smelter.

~~The~~

In November 2016, the MoPSC approved a $28 million MEEIA 2013 performance incentive ~~allowed~~based on a revised stipulation agreement between Ameren Missouri, ~~an opportunity to earn~~the MoPSC staff, and the MoOPC. As a result, Ameren Missouri will recognize $9 million of additional revenues ~~by achieving certain customer energy efficiency goals, including $19 million if 100%~~in the fourth quarter of the goals were achieved during the three-year period, with the potential to earn a larger performance incentive if Ameren Missouri’s energy savings exceeded those goals. Ameren Missouri has not recorded any revenues associated with the MEEIA 2013 performance incentive. Ameren Missouri believes it will ultimately be found to have exceeded 100% of the customer energy efficiency goals, and it therefore expects to recognize revenues2016 relating to the MEEIA 2013 performance ~~incentive~~incentive. Further, the revised stipulation agreement included a provision to incorporate the results of ~~at least $19~~the appeal, discussed below, regarding the determination of an input used to calculate the performance incentive.In November 2015, the MoPSC issued an order regarding the determination of an input used to calculate the performance incentive. Ameren Missouri filed an appeal of the order with the Missouri Court of Appeals, Western District, which is expected to issue a decision in 2016. If the Missouri Court of Appeals, Western District, overturns the November 2015 MoPSC order, Ameren Missouri may recognize additional revenues in excess of the $28 million approved by the MoPSC in November 2016.

The throughput disincentive recovery under MEEIA 2016 replaced the net shared benefits that were collected under MEEIA 2013. Net shared benefits compensated Ameren Missouri for the current year and longer-term financial impacts of customer energy efficiency programs in each year of the program from 2013 through 2015. The throughput disincentive included in MEEIA 2016, ~~on the other hand,~~however, is designed to be earnings neutral each year by compensating Ameren Missouri for the lost sales volumes from its customer energy efficiency programs that occur in that year, but does not compensate for the longer-term financial impacts of these programs until sales volumes are lost in a future year. The unfavorable on-going effects of sales volume reductions ~~in 2016~~ from the MEEIA 2013 energy efficiency programs were previously recognized during 2013 through 2015 as net shared benefits, and therefore, any such lost sales volumes have impacted and will continue to negatively impact Ameren and Ameren Missouri earnings until the date that new rates in the July 2016 ~~earnings.~~rate case become effective in May 2017.

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 reflected in customer rates for that year. Consequently, Ameren Illinois' 2016 electric distribution service revenues will be based on its 2016 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. The 2016 revenue requirement is expected to be higher

than the 2015 revenue requirement because of an expected increase in recoverable costs and rate base growth. A 50 basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $6 million change in Ameren's and Ameren Illinois' net income, based on Ameren Illinois’ 2016 projected year-end rate base.

In December 2015, the ICC issued an order with respect to Ameren Illinois’ annual update filing. The ICC approved a $106 million increase in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2016. These rates have affected and will continue to affect Ameren Illinois' cash receipts during 2016, but will not be the sole determinant of its electric distribution service operating revenues, which will instead be largely determined by the IEIMA's 2016 revenue requirement reconciliation. The 2016 revenue requirement reconciliation, as discussed above, is expected to result in a regulatory asset that will be collected from customers in 2018.

In April 2016, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for 2017 rates. Pending ICC approval, Ameren Illinois’ update filing will result in a $14 milliondecrease in Ameren Illinois’ electric distribution service revenue requirement, beginning in January 2017. This update reflects an increase to the annual formula rate based on 2015 actual costs and expected net plant additions for 2016, an increase to include the 2015 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the 2014 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2016. These rates will affect Ameren Illinois' cash receipts during 2017, but will not be the sole determinant of its electric distribution service operating revenues, which will instead be largely determined by the IEIMA's 2017 revenue requirement reconciliation.In ~~July~~October 2016, ~~the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing. The ICC staff recommended~~an administrative law judge issued a proposed order that reflected a decrease ~~in the electric distribution service revenue requirement in an amount consistent with Ameren Illinois’ filing. Other intervenors to this rate proceeding have recommended additional decreases~~ to Ameren Illinois’ electric distribution service revenue ~~requirement.~~requirement of $14 million. An ICC decision on the revenue requirement used for 2017 rates is expected by December 2016.


•	As of December 31, 2015, Ameren Missouri’s energy centers that emit CO₂ represented approximately 20% and 35% of Ameren’s and Ameren Missouri’s rate base, respectively. Ameren and Ameren Missouri estimate their investments in energy centers that emit CO₂will represent approximately 15% and 31% of Ameren’s and Ameren Missouri’s rate base by December 31, 2020.

Ameren Missouri's next scheduled refueling and maintenance outage at its Callaway energy center will be in the fall of 2017. 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, which results in limited impacts to earnings.

As we continue to experience cost increases and to 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 regulatory lag and to support investment in their utility infrastructure for the benefit of their customers. Ameren Missouri and Ameren Illinois continue to face cost recovery pressures including limited economic

growth in their service territories, customer conservation efforts, the impacts of additional customer energy efficiency programs, increased customer use of innovative and increasingly cost-effective technological advances including ~~distributed~~private generation and storage, 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 costs.

For additional information regarding recent rate orders and related appeals and pending requests filed with state and federal regulatory commissions, ~~and related appeals,~~ see Note 2 – Rate and Regulatory Matters 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

WeThrough 2020, we expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure with a major portion directed to our transmission and ~~to comply with existing environmental regulations.~~distribution systems. We estimate that we will invest in total up to $11.5 billion (Ameren Missouri – up to $4.3 billion; Ameren Illinois – up to $6.2 billion; ATXI – up to $1.0 billion) during ~~the period from~~ 2016 through ~~2020, excluding the potential impact of the Clean Power Plan.~~2020.

•

Environmental regulations, including those related to CO₂emissions, or other actions taken by the EPA could result in significant increases in capital expenditures and operating costs. These costs could be prohibitive, which could result in the closure of 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 regulatory lag. The cost of Ameren Illinois’ purchased power and gas purchased for resale could increase. However, Ameren Illinois expects these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. Ameren's and Ameren Missouri's earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in rates charged to customers.

Ameren continues to evaluate the Clean Power Plan's potential impacts to its operations, including those related to

electric system reliability, and its level of investment in customer energy efficiency programs, renewable energy, and other forms of generation investment. In February 2016, the United States Supreme Court stayed the Clean Power Plan and all implementation requirements until the legal appeals are concluded. If the rule is ultimately upheld and implemented in substantially ~~similar~~its current form, ~~to the rule when issued,~~ Ameren Missouri expects to incur increased net fuel and operating costs, and make new or accelerated capital expenditures, in addition to the costs of making

modifications to existing operations in order to achieve compliance. Compliance measures could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and natural-gas-fired energy centers, which could result in increased operating costs.

Ameren Missouri files a nonbinding integrated resource plan with the MoPSC every three years. Ameren Missouri’s integrated resource plan filed with the MoPSC in October 2014, prior to the issuance of the Clean Power Plan, was a 20-year plan that supported a more fuel-diverse energy portfolio in Missouri, including coal, solar, wind, natural gas, and nuclear power. The plan involves expanding renewable generation, retiring coal-fired generation as energy centers reach the end of their useful lives, continuation and expansion of the then-existing energy efficiency programs, and adding natural gas-fired combined cycle generation.

The Ameren Companies have multiyear credit agreements that cumulatively provide $2.1 billion of credit through December 2019, subject to a 364-day repayment term in the case of Ameren Missouri and Ameren Illinois. See Note 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information regarding the Credit Agreements. Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.

In December 2015, a federal tax law was enacted that authorized the continued use of bonus depreciation that allows for an acceleration of deductions for tax purposes at a rate of 50% for 2015, 2016, and 2017. The rate will be reduced to 40% in 2018 and then to 30% in 2019. Bonus depreciation will be phased out in 2020 unless a new law is enacted. Bonus depreciation is expected to ~~increase cash flow~~reduce or eliminate federal income tax payments through at least 2020. Ameren expects to use this incremental cash flow to make capital investments in utility infrastructure for the benefit of its customers. Without these investments, bonus depreciation would reduce rate base, which reduces our revenue requirements and future earnings growth. The impact of bonus depreciation on Ameren Missouri, Ameren Illinois, and ATXI will vary based on investment levels at each company.

As of ~~June~~September 30, 2016, Ameren had ~~$587~~$511 million in tax benefits from federal and state net operating loss carryforwards (Ameren Missouri – ~~$65~~$39 million and Ameren

Illinois – ~~$160~~$132 million) and $135 million in federal and state income tax credit carryforwards (Ameren Missouri – ~~$27~~$28 million and Ameren Illinois – $2$1 million). In addition, Ameren has $37 million of expected state income tax refunds and state overpayments. Consistent with the tax allocation agreement between Ameren and its subsidiaries, these carryforwards are expected to partially offset income tax liabilities for Ameren Missouri until 2019 and Ameren Illinois until ~~2021.~~2018. Ameren does not expect to make material federal income tax payments until 2021. These tax benefits, primarily at the Ameren (parent) level, when realized, would

be available to support funding ATXI transmission investments.

Ameren expects its cash used for capital expenditures and dividends to exceed cash provided by operating activities over the next several years. Ameren expects to use debt to fund such cash shortfalls; it does not currently expect to issue equity over the next several years.

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

REGULATORY MATTERS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

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

There have been no material changes to the quantitative and qualitative disclosures about interest rate risk, credit risk, equity price risk, commodity price risk, and commodity supplier risk included in the Form 10-K. Regarding commodity supplier risk, in April 2016, Ameren Missouri’s primary supplier of ultra-low sulfur coal announced that it had filed a voluntary petition for restructuring under Chapter 11 of the United States Bankruptcy Code. At this time, Ameren and Ameren Missouri believe the

restructuring proceeding will not affect the supplier’s performance under the terms of its existing contracts with Ameren Missouri

and therefore do not expect any material impact to Ameren Missouri’s operations as a result of this restructuring proceeding. See Item 7A under Part II of the Form 10-K for a more detailed

discussion of our market risk.

Fair Value of Contracts

We use derivatives principally to manage the risk of changes in market prices for natural gas, power, and uranium, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three and ~~six~~nine months ended ~~June~~September 30, 2016. 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 additional information regarding the methods used to determine the fair value of these contracts.


	Three Months									Six Months									Three Months									Nine Months
	Ameren Missouri			Ameren Illinois			Ameren			Ameren Missouri			Ameren Illinois			Ameren			Ameren Missouri			Ameren Illinois			Ameren			Ameren Missouri			Ameren Illinois			Ameren
Fair value of contracts at beginning of period, net	$	(37	)	$	(237	)	$	(274	)	$	(27	)	$	(219	)	$	(246	)	$	(12	)	$	(181	)	$	(193	)	$	(27	)	$	(219	)	$	(246	)
Contracts realized or otherwise settled during the period	6			19			25			1			24			25			2			7			9			8			35			43
Fair value of new contracts entered into during the period	14			—			14			13			2			15			—			(1		)	(1		)	9			(1		)	8
Other changes in fair value	5			37			42			1			12			13			(3		)	(12		)	(15		)	(3		)	(2		)	(5		)
Fair value of contracts outstanding at end of period, net	$	(12	)	$	(181	)	$	(193	)	$	(12	)	$	(181	)	$	(193	)	$	(13	)	$	(187	)	$	(200	)	$	(13	)	$	(187	)	$	(200	)

The following table presents maturities of derivative contracts as of ~~June~~September 30, 2016, 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 3-5 Years			Maturity in Excess of 5 Years			Total Fair Value			Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 3-5 Years			Maturity in Excess of 5 Years			Total Fair Value
Ameren Missouri:
Level 1	$	(11	)	$	(3	)	$	—		$	—		$	(14	)	$	(8	)	$	(1	)	$	—		$	—		$	(9	)
Level 2^(a)	(3		)	(4		)	(1		)	—			(8		)	(3		)	(6		)	—			—			(9		)
Level 3^(b)	12			(2		)	—			—			10			7			(2		)	—			—			5
Total	$	(2	)	$	(9	)	$	(1	)	$	—		$	(12	)	$	(4	)	$	(9	)	$	—		$	—		$	(13	)
Ameren Illinois:
Level 1	$	—		$	1		$	—		$	—		$	1		$	—		$	—		$	—		$	—		$	—
Level 2^(a)	(9		)	(3		)	—			—			(12		)	(7		)	(8		)	—			—			(15		)
Level 3^(b)	(12		)	(25		)	(26		)	(107		)	(170		)	(12		)	(26		)	(27		)	(107		)	(172		)
Total	$	(21	)	$	(27	)	$	(26	)	$	(107	)	$	(181	)	$	(19	)	$	(34	)	$	(27	)	$	(107	)	$	(187	)
Ameren:
Level 1	$	(11	)	$	(2	)	$	—		$	—		$	(13	)	$	(8	)	$	(1	)	$	—		$	—		$	(9	)
Level 2^(a)	(12		)	(7		)	(1		)	—			(20		)	(10		)	(14		)	—			—			(24		)
Level 3^(b)	—			(27		)	(26		)	(107		)	(160		)	(5		)	(28		)	(27		)	(107		)	(167		)
Total	$	(23	)	$	(36	)	$	(27	)	$	(107	)	$	(193	)	$	(23	)	$	(43	)	$	(27	)	$	(107	)	$	(200	)


(a)	Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed-price vs. floating over-the-counter natural gas swaps.


(b)	Principally power forward contract values based on information from external sources, historical results, and our estimates. Level 3 also includes option contract values based on an option valuation model.

ITEM 4. CONTROLS AND PROCEDURES.


(a)	Evaluation of Disclosure Controls and Procedures

As of ~~June~~September 30, 2016, 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 ~~June~~September 30, 2016, 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.

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 include the following:

Ameren Missouri’s electric rate case filed with the MoPSC in July 2016;

Ameren Missouri's appeal to the Missouri Court of Appeals, Western District, regarding the calculation of the MEEIA 2013 performance incentive;

Ameren Illinois’ annual electric distribution service formula rate update filed with the ICC in April 2016;

ATXI’s ~~requests~~lawsuits filed in October 2016 in the circuit courts of each of Adair, Knox, Marion, Schuyler, and Shelby counties in Missouri to obtain assents for ~~assents from~~road crossings in the ~~five~~ counties where the Mark Twain transmission project will be constructed;

the February 2015 complaint ~~cases~~case filed with the FERC 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; and

the class action lawsuit against Ameren Missouri relating to municipal taxes.

ITEM 1A. RISK FACTORS.

There have been no material changes to the risk factors disclosed in Part I, Item 1A, Risk Factors in the Form 10-K.

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

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

Period
(a) Total Number
of Shares
(or Units)
Purchased

(b) Average Price
Paid per Share
(or Unit)

(c) Total Number of Shares
(or Units) Purchased as Part
of Publicly Announced Plans
or Programs

(d) Maximum Number
(or Approximate Dollar Value) of
Shares (or Units) that May Yet
Be Purchased Under the Plans or
Programs
April 1 – April 30, 2016
—
$ —
—
—
May 1 – May 31, 2016 ^(a)
495
48.58
—
—
June 1 – June 30, 2016
—
—
—
—
Total 495
$ 48.58
—
—


~~(a)~~	Shares were purchased in open-market transactions pursuant to the 2014 Incentive Plan in satisfaction of Ameren’s obligations for Ameren board of directors’ compensation awards. Ameren does not have any publicly announced equity securities repurchase plans or programs.

Ameren Missouri, and Ameren Illinois did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from ~~April~~July 1, 2016 to ~~June~~September 30, 2016.

ITEM 6. EXHIBITS.

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



Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
~~Instruments Defining Rights of Security Holders, Including Indentures~~
~~4.1~~	~~Ameren~~ ~~Ameren~~ ~~Missouri~~	Ameren Missouri Indenture Company Order, dated June 23, 2016, requesting authentication of an additional $150,000,000 aggregate principal amount of 3.65% Senior Secured Notes due 2045 (including the global note)	~~June 23, 2016 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-2967~~
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.

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: ~~August 5,~~November 4, 2016

6362



Period	(a) Total Number of Shares (or Units) Purchased	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
April 1 – April 30, 2016	—	$	—	—	—
May 1 – May 31, 2016 ^(a)	495	48.58		—	—
June 1 – June 30, 2016	—	—		—	—
Total	495	$	48.58	—	—