10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Quarterly Period Ended March 31, 2017

OR

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

Commission File Number	Exact name of registrant as specified in its charter; State of Incorporation; Address and Telephone Number	IRS Employer Identification No.
1-14756	Ameren Corporation	43-1723446
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222
1-2967	Union Electric Company	43-0559760
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222
1-3672	Ameren Illinois Company	37-0211380
	(Illinois Corporation)
	6 Executive Drive
	Collinsville, Illinois 62234
	(618) 343-8150

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

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

Indicate by check mark whether each registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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

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

	Large Accelerated Filer	Accelerated Filer	Non-Accelerated Filer	Smaller Reporting Company	Emerging Growth Company
Ameren Corporation	ý	¨	¨	¨	¨
Union Electric Company	¨	¨	ý	¨	¨
Ameren Illinois Company	¨	¨	ý	¨	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Ameren Corporation	¨
Union Electric Company	¨
Ameren Illinois Company	¨

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

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

The number of shares outstanding of each registrant’s classes of common stock as of April 28, 2017, 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
	Note 1. Summary of Significant Accounting Policies	13
	Note 2. Rate and Regulatory Matters	15
	Note 3. Short-term Debt and Liquidity	16
	Note 4. Long-term Debt and Equity Financings	17
	Note 5. Other Income and Expenses	17
	Note 6. Derivative Financial Instruments	18
	Note 7. Fair Value Measurements	21
	Note 8. Related Party Transactions	25
	Note 9. Commitments and Contingencies	26
	Note 10. Callaway Energy Center	29
	Note 11. Retirement Benefits	31
	Note 12. Segment Information	31
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.	Controls and Procedures	49
PART II Other Information
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 6.	Exhibits	51
Signatures		52

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.

EMANI – European Mutual Association for Nuclear Insurance.

Form 10-K – The combined Annual Report on Form 10-K for the year ended December 31, 2016, filed by the Ameren Companies with the SEC.

Westinghouse – Westinghouse Electric Company, LLC.

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 any changes in regulatory policies and ratemaking determinations, such as those that may result from the complaint case filed in February 2015 with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff, Ameren Illinois’ April 2017 annual electric distribution 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 and the related financial commitments;

• the effects of changes in federal, state, or local laws and other governmental actions, including monetary, fiscal, 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 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 revenues and performance incentives earned under its MEEIA plans;

• Ameren Illinois’ achievement of FEJA electric energy efficiency goals and the resulting impact on its allowed return on program investments;

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

• 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 ultra-low-sulfur coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power, zero-energy credits, renewable energy credits, 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 nuclear fuel assemblies from Westinghouse, Callaway’s only NRC-licensed supplier of such assemblies, which is currently in bankruptcy proceedings;

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

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

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

• disruptions of the capital markets, deterioration in credit metrics of the Ameren Companies, or other events that may have an adverse effect on the cost or availability of capital, including short-term credit and liquidity;

• 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 impact of weather conditions on Ameren Missouri 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 transmission and distribution systems and storage facilities, such as leaks, explosions, and mechanical problems, and compliance with natural gas safety regulations;

1

• 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;

• 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 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.

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF INCOME

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

	Three Months Ended March 31,
	2017		2016
Operating Revenues:
Electric	$	1,206	$	1,102
Gas	308		332
Total operating revenues	1,514		1,434
Operating Expenses:
Fuel	206		203
Purchased power	180		138
Gas purchased for resale	130		152
Other operations and maintenance	405		400
Depreciation and amortization	221		207
Taxes other than income taxes	118		114
Total operating expenses	1,260		1,214
Operating Income	254		220
Other Income and Expenses:
Miscellaneous income	15		20
Miscellaneous expense	9		7
Total other income	6		13
Interest Charges	99		95
Income Before Income Taxes	161		138
Income Taxes	57		31
Net Income	104		107
Less: Net Income Attributable to Noncontrolling Interests	2		2
Net Income Attributable to Ameren Common Shareholders	$	102	$	105
Earnings per Common Share – Basic and Diluted	$	0.42	$	0.43
Dividends per Common Share	$	0.44	$	0.425
Average Common Shares Outstanding – Basic	242.6		242.6

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

3

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Unaudited) (In millions)

	Three Months Ended March 31,
	2017		2016
Net Income	$	104	$	107
Other Comprehensive Loss, Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes of $- and $1, respectively	—		(2		)
Comprehensive Income	104		105
Less: Comprehensive Income Attributable to Noncontrolling Interests	2		2
Comprehensive Income Attributable to Ameren Common Shareholders	$	102	$	103

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

4

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

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

	March 31, 2017			December 31, 2016
ASSETS
Current Assets:
Cash and cash equivalents	$	8		$	9
Accounts receivable – trade (less allowance for doubtful accounts of $19 and $19, respectively)	457			437
Unbilled revenue	228			295
Miscellaneous accounts receivable	67			63
Inventories	467			527
Current regulatory assets	118			149
Other current assets	105			113
Total current assets	1,450			1,593
Property, Plant, and Equipment, Net	20,298			20,113
Investments and Other Assets:
Nuclear decommissioning trust fund	635			607
Goodwill	411			411
Regulatory assets	1,485			1,437
Other assets	532			538
Total investments and other assets	3,063			2,993
TOTAL ASSETS	$	24,811		$	24,699
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	681		$	681
Short-term debt	914			558
Accounts and wages payable	460			805
Taxes accrued	77			46
Interest accrued	100			93
Customer deposits	106			107
Current regulatory liabilities	144			110
Other current liabilities	280			274
Total current liabilities	2,762			2,674
Long-term Debt, Net	6,597			6,595
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	4,321			4,264
Accumulated deferred investment tax credits	53			55
Regulatory liabilities	1,982			1,985
Asset retirement obligations	641			635
Pension and other postretirement benefits	768			769
Other deferred credits and liabilities	481			477
Total deferred credits and other liabilities	8,246			8,185
Commitments and Contingencies (Notes 2, 9, and 10)
Ameren Corporation Shareholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – 242.6 shares outstanding	2			2
Other paid-in capital, principally premium on common stock	5,522			5,556
Retained earnings	1,563			1,568
Accumulated other comprehensive loss	(23		)	(23		)
Total Ameren Corporation shareholders’ equity	7,064			7,103
Noncontrolling Interests	142			142
Total equity	7,206			7,245
TOTAL LIABILITIES AND EQUITY	$	24,811		$	24,699

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

5

AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Three Months Ended March 31,
	2017			2016
Cash Flows From Operating Activities:
Net income	$	104		$	107
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	217			210
Amortization of nuclear fuel	24			24
Amortization of debt issuance costs and premium/discounts	6			6
Deferred income taxes and investment tax credits, net	51			42
Allowance for equity funds used during construction	(6		)	(8		)
Share-based compensation costs	4			6
Other	(4		)	(3		)
Changes in assets and liabilities:
Receivables	44			55
Inventories	60			55
Accounts and wages payable	(231		)	(246		)
Taxes accrued	36			30
Regulatory assets and liabilities	7			81
Assets, other	7			7
Liabilities, other	3			(26		)
Pension and other postretirement benefits	9			9
Net cash provided by operating activities	331			349
Cash Flows From Investing Activities:
Capital expenditures	(504		)	(496		)
Nuclear fuel expenditures	(27		)	(21		)
Purchases of securities – nuclear decommissioning trust fund	(64		)	(130		)
Sales and maturities of securities – nuclear decommissioning trust fund	58			125
Other	(2		)	12
Net cash used in investing activities	(539		)	(510		)
Cash Flows From Financing Activities:
Dividends on common stock	(107		)	(103		)
Dividends paid to noncontrolling interest holders	(2		)	(2		)
Short-term debt, net	356			280
Maturities of long-term debt	—			(260		)
Share-based payments	(39		)	(32		)
Other	(1		)	(1		)
Net cash provided by (used in) financing activities	207			(118		)
Net change in cash and cash equivalents	(1		)	(279		)
Cash and cash equivalents at beginning of year	9			292
Cash and cash equivalents at end of period	$	8		$	13

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

6

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

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)

	Three Months Ended March 31,
	2017		2016
Operating Revenues:
Electric	$	746	$	694
Gas	44		47
Total operating revenues	790		741
Operating Expenses:
Fuel	206		203
Purchased power	91		42
Gas purchased for resale	20		21
Other operations and maintenance	212		212
Depreciation and amortization	133		127
Taxes other than income taxes	75		73
Total operating expenses	737		678
Operating Income	53		63
Other Income and Expenses:
Miscellaneous income	12		15
Miscellaneous expense	2		2
Total other income	10		13
Interest Charges	54		52
Income Before Income Taxes	9		24
Income Taxes	3		9
Net Income	6		15
Other Comprehensive Income	—		—
Comprehensive Income	$	6	$	15
Net Income	$	6	$	15
Preferred Stock Dividends	1		1
Net Income Available to Common Shareholder	$	5	$	14

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

7

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

BALANCE SHEET

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

	March 31, 2017		December 31, 2016
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	—
Advances to money pool	—		161
Accounts receivable – trade (less allowance for doubtful accounts of $6 and $7, respectively)	175		187
Accounts receivable – affiliates	15		12
Unbilled revenue	126		154
Miscellaneous accounts receivable	23		14
Inventories	381		392
Current regulatory assets	23		35
Other current assets	45		49
Total current assets	788		1,004
Property, Plant, and Equipment, Net	11,471		11,478
Investments and Other Assets:
Nuclear decommissioning trust fund	635		607
Regulatory assets	606		619
Other assets	314		327
Total investments and other assets	1,555		1,553
TOTAL ASSETS	$	13,814	$	14,035
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	431	$	431
Short-term debt	36		—
Accounts and wages payable	191		444
Accounts payable – affiliates	54		68
Taxes accrued	63		30
Interest accrued	53		54
Current regulatory liabilities	8		12
Other current liabilities	128		123
Total current liabilities	964		1,162
Long-term Debt, Net	3,564		3,563
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	3,017		3,013
Accumulated deferred investment tax credits	51		53
Regulatory liabilities	1,240		1,215
Asset retirement obligations	635		629
Pension and other postretirement benefits	292		291
Other deferred credits and liabilities	16		19
Total deferred credits and other liabilities	5,251		5,220
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
Other paid-in capital, principally premium on common stock	1,828		1,828
Preferred stock	80		80
Retained earnings	1,616		1,671
Total shareholders’ equity	4,035		4,090
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	13,814	$	14,035

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

8

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

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Three Months Ended March 31,
	2017			2016
Cash Flows From Operating Activities:
Net income	$	6		$	15
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	127			130
Amortization of nuclear fuel	24			24
Amortization of debt issuance costs and premium/discounts	2			2
Deferred income taxes and investment tax credits, net	2			9
Allowance for equity funds used during construction	(5		)	(7		)
Other	1			—
Changes in assets and liabilities:
Receivables	28			81
Inventories	11			(2		)
Accounts and wages payable	(186		)	(172		)
Taxes accrued	35			31
Regulatory assets and liabilities	29			45
Assets, other	11			5
Liabilities, other	4			3
Pension and other postretirement benefits	4			5
Net cash provided by operating activities	93			169
Cash Flows From Investing Activities:
Capital expenditures	(196		)	(178		)
Nuclear fuel expenditures	(27		)	(21		)
Purchases of securities – nuclear decommissioning trust fund	(64		)	(130		)
Sales and maturities of securities – nuclear decommissioning trust fund	58			125
Money pool advances, net	161			36
Other	—			(2		)
Net cash used in investing activities	(68		)	(170		)
Cash Flows From Financing Activities:
Dividends on common stock	(60		)	(140		)
Dividends on preferred stock	(1		)	(1		)
Short-term debt, net	36			165
Maturities of long-term debt	—			(260		)
Capital contribution from parent	—			38
Net cash used in financing activities	(25		)	(198		)
Net change in cash and cash equivalents	—			(199		)
Cash and cash equivalents at beginning of year	—			199
Cash and cash equivalents at end of period	$	—		$	—

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

9

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

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)

	Three Months Ended March 31,
	2017			2016
Operating Revenues:
Electric	$	439		$	392
Gas	264			285
Total operating revenues	703			677
Operating Expenses:
Purchased power	101			104
Gas purchased for resale	110			131
Other operations and maintenance	197			194
Depreciation and amortization	83			77
Taxes other than income taxes	40			38
Total operating expenses	531			544
Operating Income	172			133
Other Income and Expenses:
Miscellaneous income	3			5
Miscellaneous expense	6			5
Total other income (expense)	(3		)	—
Interest Charges	37			35
Income Before Income Taxes	132			98
Income Taxes	52			38
Net Income	80			60
Other Comprehensive Loss, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $- and $(1), respectively	—			(1		)
Comprehensive Income	$	80		$	59
Net Income	$	80		$	60
Preferred Stock Dividends	1			1
Net Income Available to Common Shareholder	$	79		$	59

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

10

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

BALANCE SHEET

(Unaudited) (In millions)

	March 31, 2017		December 31, 2016
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	—
Accounts receivable – trade (less allowance for doubtful accounts of $13 and $12, respectively)	270		242
Accounts receivable – affiliates	10		10
Unbilled revenue	102		141
Miscellaneous accounts receivable	17		22
Inventories	86		135
Current regulatory assets	91		108
Other current assets	16		25
Total current assets	592		683
Property, Plant, and Equipment, Net	7,596		7,469
Investments and Other Assets:
Goodwill	411		411
Regulatory assets	875		816
Other assets	95		95
Total investments and other assets	1,381		1,322
TOTAL ASSETS	$	9,569	$	9,474
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	250	$	250
Short-term debt	68		51
Accounts and wages payable	198		264
Accounts payable – affiliates	57		63
Taxes accrued	13		16
Interest accrued	42		33
Customer deposits	68		69
Mark-to-market derivative liabilities	18		15
Current environmental remediation	42		38
Current regulatory liabilities	118		78
Other current liabilities	88		94
Total current liabilities	962		971
Long-term Debt, Net	2,338		2,338
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,682		1,631
Accumulated deferred investment tax credits	2		2
Regulatory liabilities	739		768
Pension and other postretirement benefits	345		346
Environmental remediation	152		162
Other deferred credits and liabilities	236		222
Total deferred credits and other liabilities	3,156		3,131
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
Preferred stock	62		62
Retained earnings	1,046		967
Total shareholders’ equity	3,113		3,034
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	9,569	$	9,474

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

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

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Three Months Ended March 31,
	2017			2016
Cash Flows From Operating Activities:
Net income	$	80		$	60
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	83			77
Amortization of debt issuance costs and premium/discounts	3			4
Deferred income taxes and investment tax credits, net	51			37
Other	—			(3		)
Changes in assets and liabilities:
Receivables	16			(22		)
Inventories	49			57
Accounts and wages payable	(51		)	(33		)
Taxes accrued	(2		)	(3		)
Regulatory assets and liabilities	(19		)	32
Assets, other	2			7
Liabilities, other	(5		)	12
Pension and other postretirement benefits	5			4
Net cash provided by operating activities	212			229
Cash Flows From Investing Activities:
Capital expenditures	(227		)	(211		)
Money pool advances, net	—			(58		)
Net cash used in investing activities	(227		)	(269		)
Cash Flows From Financing Activities:
Dividends on common stock	—			(30		)
Dividends on preferred stock	(1		)	(1		)
Short-term debt, net	17			—
Other	(1		)	—
Net cash provided by (used in) financing activities	15			(31		)
Net change in cash and cash equivalents	—			(71		)
Cash and cash equivalents at beginning of year	—			71
Cash and cash equivalents at end of period	$	—		$	—

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

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AMEREN CORPORATION (Consolidated)

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

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

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

March 31, 2017

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, Ameren Illinois, and ATXI. 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. Ameren also has various other subsidiaries that conduct other activities, such as the provision of shared services. Ameren is also evaluating competitive electric transmission investment opportunities outside of MISO as they arise.

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

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

• ATXI 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’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. All tabular dollar amounts are in millions, unless otherwise indicated. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.

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. See Note 2 – Rate and Regulatory Matters for information regarding the 2017 change in Ameren Illinois' method used to recognize interim period revenue in connection with the revenue decoupling provisions of the FEJA. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

Discontinued operations were immaterial to all periods presented in Ameren’s financial statements. As such, the December 31, 2016 balance sheet presentation of discontinued operations has been reclassified in this report to “Other current assets” for assets of discontinued operations and to “Other current liabilities” for liabilities of discontinued operations. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K for additional information.

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri, and Ameren Illinois increased during the three months ended March 31, 2017, to reflect the accretion of the estimated obligation due to the passage of time, partially offset by immaterial settlements.

Share-based Compensation

A summary of nonvested performance share units at March 31, 2017, and changes during the three months ended March 31, 2017, under the 2014 Incentive Plan are presented below:

	Performance Share Units
	Share Units		Weighted-average Fair Value per Share Unit
Nonvested at January 1, 2017	1,059,639		$	48.04
Granted(a)	496,068		59.16
Forfeitures	(3,192	)	49.13
Vested(b)	(3,779	)	52.88
Nonvested at March 31, 2017	1,548,736		$	51.59

(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 vary depending on actual performance over the three-year measurement period.

The fair value of each performance share unit awarded in 2017 under the 2014 Incentive Plan was determined to be

$59.16, which was based on Ameren’s closing common share price of $52.46 at December 31, 2016, and lattice simulations.

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Lattice simulations are used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period beginning January 1, 2017 relative to the designated peer group. 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 1.47%, volatility of 15% to 21% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.

Operating Revenue

The Ameren Companies record operating revenue for electric or natural gas service when it is delivered to customers. We accrue an estimate of electric and natural gas revenues for service rendered but unbilled at the end of each accounting period. For certain regulatory recovery mechanisms qualifying as alternative revenue programs, such as revenue requirement reconciliations, the Ameren Companies recognize revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected from customers within two years.

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 therefore are 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 months ended March 31, 2017 and 2016:

	Three Months
	2017		2016
Ameren Missouri	$	31	$	30
Ameren Illinois	19		20
Ameren	$	50	$	50

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three months ended March 31, 2017 and 2016. The assumed settlement of dilutive performance share units had an immaterial impact on earnings per share. There were no potentially dilutive securities excluded from the earnings per diluted share calculations for the three months ended March 31, 2017 and 2016.

Accounting and Reporting Developments

Below is a summary of updates related to our adoption of recently issued authoritative accounting standards. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K for additional information about recently issued authoritative accounting standards relating to leases, financial instruments, restricted cash, and the consolidation analysis for variable interest entities and voting interest entities.

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative 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 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, as well as separate presentation of alternative revenue programs. Entities can apply the guidance to each reporting period presented, the full retrospective method, or by recording a cumulative effect adjustment to retained earnings in the period of initial adoption, the modified retrospective method.

During the first quarter of 2017, we determined that contributions in aid of construction and similar arrangements are not within the scope of this guidance. Therefore, our accounting for such arrangements will not change upon adoption of this guidance. In addition, we determined that the calculation of revenue and bad debt expense for tariff sales contracts will not materially change as a result of the collectibility criterion included within the guidance. We plan to complete our assessment of the impacts of this guidance on our results of operations, financial position, disclosures, and determine our transition method, in the next few months prior to our adoption in the first quarter of 2018.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In February 2017, the FASB issued authoritative guidance that requires an entity to retrospectively report the service cost component of net benefit cost in the same line item(s) as other compensation costs arising from services rendered by employees during the periodand to present the other components of net benefit cost in the income statement separately from the service cost component, and outside of operating income. The guidance also requires that an entity only capitalize the service cost component as part of an asset such as inventory or property, plant, and equipment on a prospective basis. Previously, all of the net benefit cost components were eligible for capitalization. The adoption of this guidance in the first quarter of 2018 may result in the recognition of new regulatory assets related to the recovery of, and return on, the non-service cost components of net benefit cost and related allowance for funds used during construction balances. We are currently assessing the impacts of this guidance on our results of operations, financial position, and disclosures.

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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

March 2017 Electric Rate Order

In March 2017, the MoPSC issued an order approving a unanimous stipulation and agreement in Ameren Missouri’s July 2016 regulatory rate review. The order resulted in a $3.4 billion revenue requirement, which is a $92 million increase in Ameren Missouri’s annual revenue requirement for electric service, compared to its prior revenue requirement established in the MoPSC's April 2015 electric rate order. The new rates, base level of expenses, and amortizations became effective on April 1, 2017.

The order included the continued use of the FAC and the regulatory tracking mechanisms for pension and postretirement benefits, uncertain income tax positions, and renewable energy standards that the MoPSC authorized in earlier electric rate orders. These regulatory tracking mechanisms provide for a base level of expense to be reflected in Ameren Missouri’s base electric rates with differences in the actual expenses incurred recorded as a regulatory asset or liability. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs decrease by$54 millionfrom the base level established in the MoPSC's April 2015 electric rate order. Changes in amortizations and the base level of expenses for the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, reduced expenses by$26 millionfrom the base levels established in the MoPSC's April 2015 electric rate order.

ATXI’s Mark Twain Project

The Mark Twain project is a MISO-approved 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 conditioned upon ATXI obtaining county assents for road crossings. None of the five county commissions have approved ATXI’s requests for the assents. In October 2016, ATXI filed suit in the circuit courts for each of the five counties to obtain the assents for the original project route. A decision in each of the five lawsuits is expected in late 2017. In March 2017, the MoPSC’s April 2016 order was vacated by the Missouri Court of Appeals, Western District, which ruled that the MoPSC could not lawfully grant a certificate of convenience and necessity conditioned upon ATXI obtaining the assents. ATXI is evaluating whether to appeal the March 2017 Court of Appeals decision to the Missouri Supreme Court.

In April 2017, ATXI reached agreements in principle with a

cooperative electric company in northeast Missouri and with Ameren Missouri to locate portions of the Mark Twain project on existing transmission line corridors, resulting in a proposed alternative project route. ATXI will finalize the proposed alternative project route and then request assents for road crossings from the five affected counties. If all five county commissions provide assents for the proposed alternative project route, ATXI will then seek MoPSC approval.

ATXI plans to complete the project in 2019; however, delays in obtaining the assents and approval from the MoPSC could delay completion.

Illinois

IEIMA & FEJA

Under the provisions of Illinois law, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs and allowed return on equity. This revenue requirement reconciliation qualifies as an alternative revenue program under GAAP. 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 and investment return. As of March 31, 2017, Ameren Illinois had recorded regulatory assets of $24 million and $54 million to reflect its 2016 revenue requirement reconciliation adjustment, which was included in the April 2017 formula rate update discussed below, and the approved 2015 revenue requirement reconciliation adjustment, with interest, respectively. For the three months ended March 31, 2017, Ameren Illinois recorded a regulatory asset of $46 million to reflect the difference between Ameren Illinois’ estimate of its revenue requirement and the revenue requirement reflected in customer rates.

In April 2017, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for 2018 rates. Pending ICC approval, this update filing will result in a$16 milliondecrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2018.This update reflects an increase to the annual formula rate based on 2016 actual costs and expected net plant additions for 2017, an increase to include the 2016 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the 2015 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2017, consistent with the ICC’s December 2016 annual update filing order. The revenue requirement decrease in the April 2017 update filing is a result of the 2015 revenue requirement reconciliation adjustment being larger than the 2016 revenue requirement reconciliation adjustment.An ICC decision regarding the revenue requirement to be used for customer rates in 2018 is expected by December 2017.

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The FEJA revised certain portions of the IEIMA, including extending the IEIMA formula ratemaking process through 2022, and clarifying that a common equity ratio of up to, and including, 50% is prudent. Beginning in 2017, the FEJA provides that Ameren Illinois will recover, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes. Prior to the FEJA, Ameren Illinois’ interim period revenue recognition was volume-based, as revenues were affected by the timing of sales volumes due to seasonal rates and changes in volumes resulting from, among other things, weather and energy efficiency. This previous revenue recognition method resulted in more revenues during the third quarter, and less revenues during the other quarters of each year. Beginning in 2017, in connection with the decoupling provisions of the FEJA, Ameren Illinois changed its method used to recognize interim period revenue. Ameren Illinois will now recognize revenue consistent with the timing of actual incurred electric distribution recoverable costs and recognize revenue associated with the expected return on its rate base ratably over the year. Ameren Illinois recognized $46 million and $11 million of electric distribution revenue to reflect the difference between the estimate of its revenue requirement and the revenue requirement reflected in customer rates for the three months ended March 31, 2017 and March 31, 2016, respectively.

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 FERC-regulated transmission rate base under the MISO tariff from 12.38% to 9.15%. In September 2016, the FERC issued a final order in the November 2013 complaint case, which lowered the allowed base return on common equity for the 15-month period of November 2013 to February 2015 to 10.32%, or a 10.82% total allowed return on common equity with the inclusion of the 50 basis point incentive adder for participation in an RTO. The order required customer refunds, with interest, to be issued for that 15-month period. During the first quarter of 2017,

Ameren and Ameren Illinois refunded $21 million and $17 million, respectively, related to the November 2013 complaint case. In addition, the 10.82% allowed return on common equity has been reflected in rates since September 2016.

As 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 further reduction in the allowed base return on common equity for the FERC-regulated transmission rate base under the MISO tariff. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case, which if approved by the FERC, would lower the allowed base return on common equity for the 15-month period of February 2015 to May 2016 to 9.70%, or a 10.20% total allowed return on equity with the inclusion of the 50 basis point incentive adder for participation in an RTO and require customer refunds, with interest, for that 15-month period. The timing of the issuance of the final order in the February 2015 complaint case, which will prospectively replace the current 10.82% allowed return on equity, is uncertain for two reasons. First, at this time the FERC lacks a quorum of three commissioners. Second, the United States Court of Appeals for the District of Columbia recently vacated and remanded to the FERC an order in a separate case in which the FERC established the allowed base return on common equity methodology used in the two MISO complaint cases described above. Ameren is unable to predict the impact of the outcome of the United States Court of Appeals for the District of Columbia Circuit’s remand on the MISO FERC complaint cases at this time. 

As of March 31, 2017, Ameren and Ameren Illinois recorded current regulatory liabilities of $41 million and $24 million, respectively, to reflect the expected refunds, including interest, associated with the reduced allowed returns on common equity in the initial decision in the February 2015 complaint case. Ameren Missouri does not expect that a reduction in the FERC-allowed base return on common equity would be material to its results of operations, financial position, or liquidity.

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. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, in the Form 10-K for a description of our indebtedness provisions and other covenants as well as a description of money pool arrangements.

The Missouri Credit Agreement and the Illinois Credit Agreement, both of which expire in December 2021, were not utilized for direct borrowings during the three months ended March 31, 2017, 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, the aggregate amount of credit capacity available under the Credit Agreements to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, at March 31, 2017, was $1.2 billion. The Ameren Companies were in compliance with the covenants in their credit agreements as of March 31, 2017. As of March 31, 2017, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the provisions of the Credit Agreements, were 53%, 48%, and 46% for Ameren, Ameren Missouri, and Ameren Illinois, respectively.

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Commercial Paper

The following table presents commercial paper outstanding as of March 31, 2017, and December 31, 2016:

	2017		2016
Ameren (parent)	$	810	$	507
Ameren Missouri	36		—
Ameren Illinois	68		51
Ameren Consolidated	$	914	$	558

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 three months ended March 31, 2017 and 2016:

	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated
2017
Average daily commercial paper outstanding	$	682		$	4		$	50		$	736
Weighted-average interest rate	1.07		%	0.93		%	0.95		%	1.06		%
Peak commercial paper during period(a)	$	810		$	45		$	74		$	914
Peak interest rate	1.30		%	1.15		%	1.15		%	1.30		%
2016
Average daily commercial paper outstanding	$	349		$	68		$	—		$	417
Weighted-average interest rate	0.82		%	0.80		%	—		%	0.81		%
Peak commercial paper during period(a)	$	482		$	208		$	—		$	581
Peak interest rate	0.95		%	0.85		%	—		%	0.95		%

(a) The timing of peak commercial paper issuances varies by company. Therefore, the sum of peak commercial paper issuances presented by company does not equal the Ameren Consolidated peak commercial paper issuances for the period.

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.

The average interest rate for borrowing under the utility money pool for the three months ended March 31, 2017 and 2016, was 1.01% and 0.47%, respectively.

See Note 8 – Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three months ended March 31, 2017 and 2016.

NOTE 4 – LONG-TERM DEBT AND EQUITY FINANCINGS

Indenture Provisions and Other Covenants

Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to

issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions, but would restrict the companies’ ability to issue first mortgage bonds or preferred stock. See Note 5 – Long-Term Debt and Equity Financings under Part II, Item 8, in the Form 10-K for a description of our indenture provisions and other covenants as well as restrictions on the payment of dividends. The Ameren Companies were in compliance with those indenture provisions and other covenants as of March 31, 2017.

Off-Balance-Sheet Arrangements

At March 31, 2017, 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 three months ended March 31, 2017 and 2016:

	Three Months
	2017	2016
Ameren:(a)
Miscellaneous income:

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	Three Months
	2017		2016
Allowance for equity funds used during construction	$	6	$	8
Interest income on industrial development revenue bonds	7		7
Interest income	2		4
Other	—		1
Total miscellaneous income	$	15	$	20
Miscellaneous expense:
Donations	$	5	$	5
Other	4		2
Total miscellaneous expense	$	9	$	7
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	5	$	7
Interest income on industrial development revenue bonds	7		7
Other	—		1
Total miscellaneous income	$	12	$	15
Miscellaneous expense:
Donations	$	—	$	1
Other	2		1
Total miscellaneous expense	$	2	$	2
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	1	$	1
Interest income	2		4
Total miscellaneous income	$	3	$	5
Miscellaneous expense:
Donations	$	4	$	4
Other	2		1
Total miscellaneous expense	$	6	$	5

(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.

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The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of March 31, 2017 and December 31, 2016. As of March 31, 2017, these contracts extended through October 2019, March 2023, May 2032, and February 2020 for fuel oils, natural gas, power, and uranium, respectively.

	Quantity (in millions, except as indicated)
	2017			2016
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)(a)	36	(b)	36	30	(b)	30
Natural gas (in mmbtu)	28	149	177	25	129	154
Power (in megawatthours)	1	9	10	1	9	10
Uranium (pounds in thousands)	345	(b)	345	345	(b)	345

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

(b) Not applicable.

All contracts considered to be derivative instruments are required to 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 March 31, 2017 and December 31, 2016, all contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral.

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The following table presents the carrying value and balance sheet location of all derivative commodity contracts, none of which were designated as hedging instruments, as of March 31, 2017 and December 31, 2016:

	Balance Sheet Location	Ameren Missouri			Ameren Illinois		Ameren
2017
Fuel oils	Other current assets	$	1		$	—	$	1
	Other assets	1			—		1
Natural gas	Other current assets	—			5		5
Power	Other current assets	5			—		5
	Total assets (a)	$	7		$	5	$	12
Fuel oils	Other current liabilities	$	5		$	—	$	5
Natural gas	MTM derivative liabilities	(b)			6		(b)
	Other current liabilities	2			—		8
	Other deferred credits and liabilities	6			9		15
Power	MTM derivative liabilities	(b)			12		(b)
	Other current liabilities	1			—		13
	Other deferred credits and liabilities	—			182		182
Uranium	Other deferred credits and liabilities	—		(c)	—		—		(c)
	Total liabilities (d)	$	14		$	209	$	223
2016
Fuel oils	Other current assets	$	2		$	—	$	2
	Other assets	1			—		1
Natural gas	Other current assets	1			11		12
	Other assets	1			2		3
Power	Other current assets	9			—		9
	Total assets (a)	$	14		$	13	$	27
Fuel oils	Other current liabilities	$	5		$	—	$	5
Natural gas	MTM derivative liabilities	(b)			3		(b)
	Other current liabilities	1			—		4
	Other deferred credits and liabilities	5			5		10
Power	MTM derivative liabilities	(b)			12		(b)
	Other current liabilities	3			—		15
	Other deferred credits and liabilities	—			173		173
Uranium	Other deferred credits and liabilities	4			—		4
	Total liabilities (d)	$	18		$	193	$	211

(a) 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) Beginning in 2017, as a result of rulebook amendments at the Chicago Mercantile Exchange, the fair value of uranium derivative liabilities are offset by certain settlement payments made to the exchange previously characterized as collateral and included within “Other assets” on Ameren’s and Ameren Missouri’s balance sheet.

(d) 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; these contracts 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 Ameren Companies elect to present the fair value amounts of derivative assets and derivative liabilities subject to an enforceable master netting arrangement or similar agreement gross on the balance sheet. However, if the gross amounts recognized on the balance sheet were netted with derivative instruments and cash collateral received or posted, the net amounts would not be materially different from the gross amounts at March 31, 2017 and December 31, 2016.

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Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into groupings according to the primary business in which each engages. We calculate maximum exposures based on the gross fair value of financial instruments, including NPNS and other accrual contracts. These exposures are calculated on a gross basis, which include affiliate exposure not eliminated at the consolidated Ameren level. As of March 31, 2017, 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 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 March 31, 2017, 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 March 31, 2017, 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)
2017
Ameren Missouri	$	58	$	8	$	44
Ameren Illinois	38		—		30
Ameren	$	96	$	8	$	74

(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 March 31, 2017 and December 31, 2016:

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
Level 3 Derivative asset and liability – commodity contracts(a):
2017
	Fuel oils	$	1	$	(1	)	Option model	Volatilities(%)(b)	23 – 35	27
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.12 – 0.22	0.15

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		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
								Ameren Missouri credit risk(%)(c)(d)	0.37	(e)
								Escalation rate (%)(b)(f)	0 – 1	0
	Natural gas	—		(2		)	Discounted cash flow	Nodal basis ($/mmbtu)(b)	(0.80) – (0.10)	(0.70)
								Counterparty credit risk (%)(c)(d)	0.45 – 6	0.70
								Ameren Illinois credit risk (%)(c)(d)	0.37	(e)
	Power(g)	5		(195		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)(h)	25 – 44	29
								Estimated auction price for FTRs ($/MW)(b)	(89) – 1,568	164
								Nodal basis ($/MWh)(h)	(4) – 0	(2)
								Ameren Illinois credit risk (%)(c)(d)	0.37	(e)
							Fundamental energy production model	Estimated future gas prices ($/mmbtu)(b)	3 – 4	3
								Escalation rate (%)(b)(i)	3	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(b)	5 – 7	6
2016
	Fuel oils	$	1	$	—		Option model	Volatilities (%)(b)	24 – 66	28
							Discounted cash flow	Counterparty credit risk (%)(c)(d)	0.13 – 0.22	0.15
								Ameren Missouri credit risk (%)(c)(d)	0.38	(e)
								Escalation rate (%)(b)(f)	(2) – 2	0
	Natural gas	1		(1		)	Option model	Volatilities (%)(b)	31 – 66	36
								Nodal basis ($/mmbtu)(b)	(0.40) – (0.10)	(0.20)
							Discounted cash flow	Nodal basis ($/mmbtu)(b)	(0.80) – 0	(0.50)
								Counterparty credit risk (%)(c)(d)	0.13 – 8	1
								Ameren Illinois credit risk (%)(c)(d)	0.38	(e)
	Power(g)	9		(187		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)(h)	26 – 44	29
								Estimated auction price for FTRs ($/MW)(b)	(71) – 5,270	125
								Nodal basis ($/MWh)(h)	(6) – 0	(2)
								Ameren Illinois credit risk (%)(c)(d)	0.38	(e)
							Fundamental energy production model	Estimated future gas prices ($/mmbtu)(b)	3 – 4	3
								Escalation rate (%)(b)(i)	5	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(b)	5 – 7	6
	Uranium	—		(4		)	Option model	Volatilities (%)(b)	24	(e)
							Discounted cash flow	Average forward uranium pricing ($/pound)(b)	22 – 24	22
								Ameren Missouri credit risk (%)(c)(d)	0.38	(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) Escalation rate applies to fuel oil prices 2019 and beyond

(g) Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2021 for March 31, 2017 and through 2020 for December 31, 2016. Valuations beyond 2021 for March 31, 2017 and 2020 for December 31, 2016 use fundamentally modeled pricing by month for peak and off-peak demand.

(h) 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.

(i) Escalation rate applies to power prices in 2031 and beyond.

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 quarter of 2017 or 2016. At March 31, 2017 and December 31,

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2016, 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 March 31, 2017:

		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable  Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
Ameren	Derivative assets – commodity contracts(a):
	Fuel oils	$	1	$	—	$	1	$	2
	Natural gas	1		4		—		5
	Power	—		—		5		5
	Total derivative assets – commodity contracts	$	2	$	4	$	6	$	12
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	420		—		—		420
	Debt securities:
	U.S. treasury and agency securities	—		118		—		118
	Corporate bonds	—		70		—		70
	Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	421	$	212	$	—	$	633	(b)
	Total Ameren	$	423	$	216	$	6	$	645
Ameren Missouri	Derivative assets – commodity contracts(a):
	Fuel oils	$	1	$	—	$	1	$	2
	Power	—		—		5		5
	Total derivative assets – commodity contracts	$	1	$	—	$	6	$	7
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	420		—		—		420
	Debt securities:
	U.S. treasury and agency securities	—		118		—		118
	Corporate bonds	—		70		—		70
	Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	421	$	212	$	—	$	633	(b)
	Total Ameren Missouri	$	422	$	212	$	6	$	640
Ameren Illinois	Derivative assets – commodity contracts(a):
	Natural gas	$	1	$	4	$	—	$	5
Liabilities:
Ameren	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	4	$	—	$	1	$	5
	Natural gas	—		21		2		23
	Power	—		—		195		195
	Total Ameren	$	4	$	21	$	198	$	223
Ameren Missouri	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	4	$	—	$	1	$	5
	Natural gas	—		8		—		8
	Power	—		—		1		1
	Total Ameren Missouri	$	4	$	8	$	2	$	14
Ameren Illinois	Derivative liabilities – commodity contracts(a):
	Natural gas	$	—	$	13	$	2	$	15
	Power	—		—		194		194
	Total Ameren Illinois	$	—	$	13	$	196	$	209

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

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

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The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 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
Assets:
Ameren	Derivative assets – commodity contracts(a):
	Fuel oils	$	2	$	—	$	1	$	3
	Natural gas	2		12		1		15
	Power	—		—		9		9
	Total derivative assets – commodity contracts	$	4	$	12	$	11	$	27
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	408		—		—		408
	Debt securities:
	U.S. treasury and agency securities	—		112		—		112
	Corporate bonds	—		67		—		67
	Other	—		17		—		17
	Total nuclear decommissioning trust fund	$	409	$	196	$	—	$	605	(b)
	Total Ameren	$	413	$	208	$	11	$	632
Ameren Missouri	Derivative assets – commodity contracts(a):
	Fuel oils	$	2	$	—	$	1	$	3
	Natural gas	—		1		1		2
	Power	—		—		9		9
	Total derivative assets – commodity contracts	$	2	$	1	$	11	$	14
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	408		—		—		408
	Debt securities:
	U.S. treasury and agency securities	—		112		—		112
	Corporate bonds	—		67		—		67
	Other	—		17		—		17
	Total nuclear decommissioning trust fund	$	409	$	196	$	—	$	605	(b)
	Total Ameren Missouri	$	411	$	197	$	11	$	619
Ameren Illinois	Derivative assets – commodity contracts(a):
	Natural gas	$	2	$	11	$	—	$	13
Liabilities:
Ameren	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	5	$	—	$	—	$	5
	Natural gas	—		13		1		14
	Power	—		1		187		188
	Uranium	—		—		4		4
	Total Ameren	$	5	$	14	$	192	$	211
Ameren Missouri	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	5	$	—	$	—	$	5
	Natural gas	—		6		—		6
	Power	—		1		2		3
	Uranium	—		—		4		4
	Total Ameren Missouri	$	5	$	7	$	6	$	18
Ameren Illinois	Derivative liabilities – commodity contracts(a):
	Natural gas	$	—	$	7	$	1	$	8
	Power	—		—		185		185
	Total Ameren Illinois	$	—	$	7	$	186	$	193

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

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

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All costs related to financial assets and liabilities classified as Level 3 in the fair value hierarchy 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 months ended March 31, 2017 and 2016, 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.

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:

		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
For the three months ended March 31, 2017
Beginning balance at January 1, 2017	$	7		$	(185	)	$	(178	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			(10	)		(10	)
Settlements		(3	)		1			(2	)
Ending balance at March 31, 2017	$	4		$	(194	)	$	(190	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2017	$	—		$	(11	)	$	(11	)
For the three months ended March 31, 2016
Beginning balance at January 1, 2016	$	16		$	(170	)	$	(154	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(3	)		(21	)		(24	)
Settlements		(7	)		4			(3	)
Ending balance at March 31, 2016	$	6		$	(187	)	$	(181	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2016	$	—		$	(19	)	$	(19	)

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. For the three months ended March 31, 2017 and 2016, there were no material transfers between Level 1 and Level 2, Level 1 and Level 3, or 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 March 31, 2017 and December 31, 2016:

	March 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:
Long-term debt and capital lease obligations (including current portion)	$	7,278	$	7,762	$	7,276	$	7,772
Preferred stock(a)	142		129		142		131
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	3,995	$	4,312	$	3,994	$	4,304
Preferred stock	80		77		80		79
Ameren Illinois:
Long-term debt (including current portion)	$	2,588	$	2,742	$	2,588	$	2,765
Preferred stock	62		52		62		52

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

NOTE 8 – RELATED PARTY TRANSACTIONS

In the normal course of business, the Ameren Companies engage in affiliate transactions. These transactions primarily consist of power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between

affiliates are reported as intercompany transactions on their financial statements but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our material related party agreements, see Note 14 – Related Party Transactions under Part II, Item 8, of the Form 10-K and the

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money pool arrangements discussed in Note 3 – Short-term Debt and Liquidity of this report.

Electric Power Supply Agreement

In April 2017, Ameren Illinois conducted a procurement event, administered by the IPA, to purchase energy products. Ameren Missouri was among the winning suppliers in this event.

As a result, in April 2017, Ameren Missouri and Ameren Illinois entered into an energy product agreement by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, 85,600 megawatthours at an average price of $33.64 per megawatthour during the period of March 1, 2019, through May 31, 2020.

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three months ended March 31, 2017 and 2016:

				Three Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2017	$	11	$	(a)
agreements with Ameren Illinois		2016		9		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2017		7		1
rent and facility services		2016		6		1
Total Operating Revenues		2017	$	18	$	1
		2016		15		1
Ameren Illinois power supply	Purchased Power	2017	$	(a)	$	11
agreements with Ameren Missouri		2016		(a)		9
Ameren Illinois transmission	Purchased Power	2017		(a)		(b)
services with ATXI		2016		(a)		(b)
Total Purchased Power		2017	$	(a)	$	11
		2016		(a)		9
Ameren Services support services	Other Operations and Maintenance	2017	$	35	$	32
agreement		2016		34		31
Money pool borrowings (advances)	Interest Charges/ Miscellaneous Income	2017	$	(b)	$	(b)
		2016		(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, and Note 15 – Commitments and Contingencies 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 of this report.

Other Obligations

In 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 March 31, 2017, 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 $3,824 million, $2,340 million, and $1,418 million, respectively. For additional information regarding our obligations and commitments at December 31, 2016, see Note 15 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

In April 2017, Ameren Illinois conducted a procurement event, administered by the IPA, to purchase energy products through May 31, 2020. In the April 2017 procurement event, Ameren Illinois contracted to purchase 4,249,800 megawatthours of energy products for $128 million from June 1, 2017, through May 31, 2020. See Note 8 – Related Party Transactions for

26

additional information regarding energy product agreements between Ameren Missouri and Ameren Illinois as a result of this procurement event.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. The development and operation of electric generation, transmission, and distribution facilities and natural gas storage, transmission, and distribution facilities, can trigger compliance obligations with respect to diverse environmental laws and regulations. These laws and regulations address emissions, discharges to water, water usage, impacts to air, land, and water, and chemical and waste handling. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures.

The EPA has promulgated environmental regulations that 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. As of December 31, 2016, Ameren Missouri’s fossil-fueled energy centers represented 18% and 34% of Ameren’s and Ameren Missouri’s rate base, respectively. Recent regulations impacting air emissions from electric utility industry include revised NSPS, the CSAPR, the MATS and revised National Ambient Air Quality Standards, which are subject to periodic review for certain pollutants. Collectively, these regulations cover a variety of pollutants such as SO₂, particulate matter, NO_X, mercury, toxic metals and acid gases. Regulation of CO₂ emissions from existing power plants through the Clean Power Plan have been stayed by the United States Supreme Court. In addition, the EPA recently announced it is re-evaluating the legal and policy basis for the Clean Power Plan. Water intake and discharges from power plants are regulated under the Clean Water Act and could require significant capital expenditures, such as modifications to water intake structures at Ameren Missouri’s energy centers. The management and disposal of coal ash is regulated under the CCR Rule, which will require significant capital expenditures, such as the closure of surface impoundments and the installations of dry ash handling systems at several of our energy centers. The EPA has initiated an administrative review of several regulations and rulemaking activities, including the Clean Power Plan, the MATS, and the effluent limitation guidelines, which could ultimately result in the revision of all or part of such rules. However, the individual or combined effects of existing environmental regulations could result in significant capital expenditures and increased operating costs for Ameren and Ameren Missouri. Compliance with existing 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 further capital investment. Ameren and Ameren Missouri expect that such compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the timing of costs and their recovery could be subject to regulatory lag.

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 $425 million to $525 million in the aggregate from 2017 through 2021 in order to comply with existing environmental regulations. Ameren Missouri may be required to install additional environmental controls beyond 2021. This estimate of capital expenditures includes 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. 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 because of uncertainty as to whether the EPA will substantively revise regulatory obligations, 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 SO₂ and 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. The second phase of emission reduction requirements, which were revised by the EPA in 2016, became 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 did not make additional capital investments to comply with the 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

In 2015, the EPA issued 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. The Clean Power Plan sets forth CO₂ emissions standards applicable to existing power plants. The rule was stayed by the United States Supreme Court in February 2016, pending the outcome of various legal challenges. In April 2017, the EPA announced that it is reviewing and, if appropriate, will initiate proceedings to suspend, revise, or rescind the Clean Power Plan. The District of Columbia Circuit Court of Appeals has stayed further action on the litigation that

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resulted from the Supreme Court’s February 2016 stay of the Clean Power Plan pending the EPA’s administrative review.

The Clean Power Plan would require significant reductions in CO₂ emissions from power plants by 2030 including interim compliance periods commencing in 2022. The EPA has advised all states to discontinue implementation planning. We cannot predict the outcome of the EPA’s administrative review, nor the resulting impact on our results of operations, financial position, or liquidity.

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 complaint, as amended in October 2013, alleged 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. The litigation has been divided into two phases: liability and remedy. In January 2017, the district court issued a liability ruling that the projects violated provisions of the Clean Air Act and Missouri law. The case will now proceed to the second phase to determine the actions required to remedy the violations found in the liability phase of the litigation. The EPA previously withdrew all claims for penalties and fines. At the conclusion of both phases of the litigation, Ameren Missouri intends to appeal the liability ruling to the United States Circuit Court of Appeals for the Eighth Circuit. A decision by the district court regarding the remedy phase of the litigation could occur in 2019.

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. Among other things and subject to economic and regulatory considerations, resolution of this matter could result in increased capital expenditures for the installation of pollution control equipment, as well as increased operations and maintenance expenses. We are unable to predict the ultimate resolution of 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. All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to the cooling water intake structures rule. Implementation of the rule will occur during the permit renewal process of each energy center’s water discharge permit, which will occur between 2018 and 2023.

Additionally, in 2015, the EPA issued a rule to revise the effluent limitation guidelines applicable to steam electric generating units. These guidelines established national standards for water discharges that are based on the effectiveness of available control technology. The EPA's 2015 rule prohibits effluent discharges of certain waste streams and imposes more

stringent limitations on certain water discharges from power plants. In April 2017, the EPA announced that it would review and reconsider the effluent limitation guidelines and administratively stayed all compliance deadlines.

Both the intake and effluent rules, if implemented as enacted, could have an adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity should such implementation require extensive modifications to the cooling water systems and water discharge systems at Ameren Missouri’s energy centers, and if such 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 from coal fired energy centers. These regulations affect CCR disposal and handling costs at Ameren Missouri's energy centers. They require closure of impoundments if performance criteria relating to groundwater impacts and location restrictions are not achieved. Ameren and Ameren Missouri’s AROs associated with CCR storage facilities reflect the regulations issued in 2015. Ameren plans to close these CCR storage facilities between 2018 and 2023.

Ameren Missouri's capital expenditure plan includes the cost of constructing landfills as part of its environmental compliance plan.

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 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 March 31, 2017, 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 2023. 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 March 31, 2017, Ameren Illinois estimated the obligation related to these former MGP sites at $193 million to $258 million. Ameren and Ameren Illinois recorded a liability of $193 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate.

The scope of the remediation activities at these former MGP sites may increase as remediation efforts continue. Considerable uncertainty remains in these estimates because many site-

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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 Missouri 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 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 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 remedies. As of March 31, 2017, 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.

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 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 March 31, 2017, and December 31, 2016, representing their estimate of the probable loss due as a result of this lawsuit. Ameren and Ameren Missouri believe there is a remote possibility that a liability relating to this lawsuit could be material to Ameren's 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. A 2018 trial has been set and an order is expected later that year.

NOTE 10 – CALLAWAY ENERGY CENTER

Spent Nuclear Fuel

Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. The NWPA established the fee that Ameren Missouri and other utilities that own and operate those energy centers 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 was suspended in May 2014. 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 fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners sued the DOE to recover costs incurred for ongoing storage of their spent fuel. The lawsuit resulted in a settlement agreement that provides for annual reimbursement of additional spent fuel storage and related costs. For the three months ended March 31, 2017 and March 31, 2016, Ameren Missouri did not receive any such reimbursements. Ameren Missouri will continue to apply for reimbursement from the DOE for allowable costs associated with the ongoing storage of spent fuel.

Decommissioning

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

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2016, the MoPSC approved no change in the annual decommissioning costs used to establish electric rates.

The fair value of the trust fund for Ameren Missouri's Callaway energy center is reported as "Nuclear decommissioning trust fund" in Ameren's and Ameren Missouri's balance sheets. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory liability. 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.

Supplier of Fuel Assemblies

The next scheduled refueling and maintenance outage at Ameren Missouri’s Callaway energy center will be in fall 2017. The Callaway energy center uses nuclear fuel assemblies fabricated by Westinghouse. Westinghouse is currently the only NRC-licensed supplier authorized to provide fuel assemblies to the Callaway energy center. During the first quarter of 2017, Westinghouse filed voluntary petitions for a court-supervised

restructuring process under Chapter 11 of the United States Bankruptcy Code. Westinghouse could petition the bankruptcy court to reject Ameren Missouri’s contracts as part of the restructuring process, and if the bankruptcy court agrees, this could result in Ameren Missouri not having access to the fuel assemblies necessary to operate the Callaway energy center. At this time, Ameren and Ameren Missouri believe the restructuring proceeding will not affect Westinghouse’s performance under the terms of its existing contracts with Ameren Missouri, including with respect to the delivery of fuel assembles for the upcoming refueling and maintenance outage, and therefore do not expect any material impact to Ameren Missouri’s operations as a result of this restructuring proceeding. However, Ameren and Ameren Missouri could incur material unexpected costs as a result of the Westinghouse bankruptcy, such as the cost of replacement power, the loss of fuel inventory that is stored at Westinghouse’s facility, and payments made for fuel fabrication. A change of fuel suppliers or a change in the type of fuel assembly design that is currently licensed for use at the Callaway energy center could take an estimated three years of analysis and NRC licensing efforts to implement.

Insurance

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at March 31, 2017. The property coverage and the nuclear liability coverage renewal dates are April 1 and January 1, respectively, of each year. Both coverages were renewed in 2017.

Type and Source of Coverage	Maximum  Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	450		$	—
Pool participation	12,986		(a)	127		(b)
	$	13,436	(c)	$	127
Property damage:
NEIL and EMANI	$	3,200	(d)	$	29	(e)
Replacement power:
NEIL	$	490	(f)	$	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 $450 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. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.

(d) NEIL provides $2.7 billion in property damage, stabilization, decontamination, and premature decommissioning insurance for radiation events and $2.3 billion in property damage for nonradiation events. EMANI provides $490 million for both radiation and nonradiation events.

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

(f) 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 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 subject to industrywide aggregates, such that terrorist acts against one or more commercial nuclear power plants insured by NEIL or EMANI within a stated time period would be treated as a single event, and the owners of the nuclear power plants would share one full limit of liability. NEIL policies have an aggregate limit of $3.2 billion within a 12-month

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period for radiation events, or $1.8 billion for events not involving radiation contamination. The EMANI policies have an aggregate limit of €600 million for radiation and nonradiation events within a period of 72 hours.

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.

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 months ended March 31, 2017 and 2016:

	Pension Benefits						Postretirement Benefits
	Three Months						Three Months
	2017			2016			2017			2016
Service cost	$	23		$	20		$	5		$	5
Interest cost	45			47			12			12
Expected return on plan assets	(66		)	(63		)	(19		)	(18		)
Amortization of:
Prior service benefit	—			—			(1		)	(1		)
Actuarial loss (gain)	14			9			(2		)	(3		)
Net periodic benefit cost (benefit)	$	16		$	13		$	(5	)	$	(5	)

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 months ended March 31, 2017 and 2016:

	Pension Benefits				Postretirement Benefits
	Three Months				Three Months
	2017		2016		2017			2016
Ameren Missouri(a)	$	6	$	8	$	(1	)	$	(1	)
Ameren Illinois	10		5		(4		)	(4		)
Ameren(a)(b)	$	16	$	13	$	(5	)	$	(5	)

(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 – SEGMENT INFORMATION

Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. Ameren Illinois Natural Gas consists of the natural gas business of Ameren Illinois. Ameren Transmission is primarily composed of the aggregated electric transmission businesses of Ameren Illinois and ATXI, and associated Ameren (parent) interest charges. The category called Other primarily includes Ameren parent company activities and Ameren Services.

Ameren Missouri has one segment. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. See Note 1 – Summary of Significant Accounting Policies for additional information regarding the operations of Ameren Missouri and Ameren Illinois.

Segment operating revenues and a majority of operating expenses are directly recognized and incurred by Ameren Illinois to each Ameren Illinois segment. Common operating expenses, miscellaneous income and expenses, interest charges, and income tax expense are allocated by Ameren Illinois to each Ameren Illinois segment based on certain factors, which primarily relate to the nature of the cost. Additionally, Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. The transmission expense for Illinois customers who have elected to purchase their power from Ameren Illinois is recovered through a cost recovery mechanism with no net effect on Ameren Illinois Electric Distribution earnings, as costs are offset by corresponding revenues. Transmission revenues from these transactions are reflected at Ameren Transmission and Ameren Illinois Transmission. An intersegment elimination at Ameren and Ameren Illinois occurs to eliminate these transmission revenues and expenses.

The following tables present information about the reported revenues and specified items reflected in net income attributable to common shareholders and capital expenditures at Ameren and Ameren Illinois for the three months ended March 31,2017 and 2016. Ameren, Ameren

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Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.

Ameren

Three Months	Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission			Other				Intersegment Eliminations			Consolidated
2017
External revenues	$	772	$	384	$	264	$	96		$	(2	)		$	—		$	1,514
Intersegment revenues	18		1		—		6		(a)	—				(25		)	—
Net income attributable to Ameren common shareholders	5		30		33		34			—				—			102
Capital expenditures	196		120		51		134			4			(b)	(1		)	504
2016
External revenues	$	726	$	351	$	285	$	72		$	—			$	—		$	1,434
Intersegment revenues	15		1		—		11		(a)	—				(27		)	—
Net income attributable to Ameren common shareholders	14		11		35		27			18				—			105
Capital expenditures	178		117		35		164			2			(b)	—			496

(a) Ameren Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above.

(b) Includes the elimination of intercompany transfers.    

Ameren Illinois

	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission			Intersegment Eliminations			Consolidated
2017
External revenues	$	385	$	264	$	54		$	—		$	703
Intersegment revenues	—		—		6		(a)	(6		)	—
Net income available to common shareholder	30		33		16			—			79
Capital expenditures	120		51		56			—			227
2016
External revenues	$	352	$	285	$	40		$	—		$	677
Intersegment revenues	—		—		11		(a)	(11		)	—
Net income available to common shareholder	11		35		13			—			59
Capital expenditures	117		35		59			—			211

(a) Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above.

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

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

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005. 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.

Below is a summary description of Ameren's principal subsidiaries. Ameren also has various other subsidiaries that conduct other activities, such as the provision of shared services. Ameren is also evaluating competitive electric transmission investment opportunities outside of MISO as they arise.

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

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

• ATXI 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’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. 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 was $102 million in the first quarter of 2017, compared with $105 million in the year-ago period. Net income was unfavorably affected by an increase in the effective tax rate primarily due to a decrease in the income tax benefit recorded at Ameren (parent) related to share-based compensation. Earnings also decreased as a result of milder winter temperatures in 2017 and increased depreciation and amortization expenses. Net income was favorably affected by a change in the method used to recognize interim period revenue related to Ameren Illinois Electric Distribution’s revenue requirement reconciliation in connection with the decoupling provisions of the FEJA. Additionally, earnings were favorably affected by increased Ameren Transmission and Ameren Illinois Electric Distribution investment, reflecting Ameren’s strategy to allocate incremental capital to those businesses, as well as decreased other operations and maintenance expenses.

Ameren’s strategic plan includes investing in and operating its utilities in a manner consistent with existing regulatory frameworks, enhancing those frameworks and advocating for responsible energy and economic policies, as well as creating and capitalizing on opportunities for investment for the benefit of its customers and shareholders. Ameren remains focused on disciplined cost management and strategic capital allocation. In the first quarter of 2017, Ameren continued to allocate significant amounts of capital to those businesses that are supported by constructive regulatory frameworks, investing more than $300 million of capital expenditures in its FERC rate-regulated electric transmission and Illinois electric and natural gas distribution businesses.

In March 2017, the MoPSC issued an order approving a unanimous stipulation and agreement in Ameren Missouri’s July 2016 regulatory rate review. The electric rate order resulted in a $92 million increase in Ameren Missouri’s revenue requirement, a $54 million decrease in the base level of net energy costs, and a $26 million reduction in the base level of certain tracked expenses, compared to the amounts in the MoPSC’s April 2015 rate order. The new rates and base level of expenses became effective on April 1, 2017.

Ameren Illinois invested approximately $170 million in electric distribution and natural gas infrastructure projects in the first quarter of 2017, including those that are part of its modernization action plan. In April 2017, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for 2018 rates. Pending ICC approval, this update filing will result in a$16 milliondecrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2018.This update reflects an increase to the annual formula rate based on 2016 actual costs and expected net plant additions for 2017, an increase to include the 2016 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the 2015 revenue requirement

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reconciliation adjustment, which will be fully collected from customers in 2017. An ICC decision on the revenue requirement to be used for 2018 rates is expected by December 2017.

In the first quarter of 2017, Ameren Transmission invested approximately $135 million in FERC rate-regulated electric transmission projects, including the Illinois Rivers project, the Spoon Rivers project, and Ameren Illinois’ transmission projects to maintain and improve reliability. ATXI’s construction activities for its Illinois Rivers and Spoon River projects are continuing on schedule and are expected to be completed by 2019 and 2018, respectively. Related to its Mark Twain project, in March 2017, the Missouri Court of Appeals, Western District, vacated a MoPSC April 2016 order that had granted a certificate of convenience and necessity for the Mark Twain project, and ruled that the MoPSC could not lawfully grant a certificate of convenience and necessity conditioned upon ATXI obtaining the county assents for road crossings. ATXI is evaluating whether to appeal this ruling to the Missouri Supreme Court. In April 2017, ATXI reached agreements in principle with a cooperative electric company in northeast Missouri and with Ameren Missouri to locate portions of that project on existing transmission line corridors, resulting in a proposed alternative project route. ATXI will finalize the proposed alternative project route and then request assents for road crossings from the five affected counties. If all five county commissions provide assents for the proposed alternative project route, ATXI will then seek MoPSC approval.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Economic conditions, energy efficiency investments by our customers and us, and the actions of key customers can significantly affect the demand for our services. Ameren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling demands as well as 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, demand, and many other factors. As described below, 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 Missouri’s FAC cost recovery mechanism 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 retained by Ameren Missouri. Net energy costs, as defined in the FAC, include fuel and purchased power costs net of off-system sales. Ameren Missouri accrues net energy costs that exceed the amount set in base rates (FAC under-recovery) as a regulatory asset. 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. See the definition of margin in the Electric and Natural Gas Margins section below. Ameren Missouri also 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 any change in costs is offset by a corresponding change in revenues.

Ameren Illinois’ electric distribution service business has a cost recovery mechanism for power purchased and transmission services incurred on behalf of its customers. Ameren Illinois’ natural gas business has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through costs do not affect Ameren Illinois' electric or natural gas margins, as any change in costs is offset by a corresponding change in revenues.

Under the provisions of Illinois law, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs and allowed return on equity. If a given 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 amounts from customers within two years. If a given 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 two years.

Included in Ameren Illinois' electric distribution service 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 for its electric distribution business is directly correlated to yields on United States Treasury bonds. Recoverable electric distribution costs that are not recovered through separate cost recovery mechanisms are also included in a revenue requirement reconciliation which results in corresponding adjustments to electric revenues, with no overall effect on net income. These recoverable electric distribution costs include other operations and maintenance expenses, depreciation and amortization, taxes

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other than income taxes, interest charges, and income taxes. A portion of the electric distribution costs included in those income statement rows are not recoverable based on the IEIMA’s formula rate framework. Beginning in 2017, the FEJA also provides that Ameren Illinois recovers, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes.

The provisions of FERC's electric transmission formula rate framework provide for an annual reconciliation of the electric transmission service revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement in customer rates for that year, including an allowed return on equity. Ameren Illinois and ATXI use a company-specific, forward-looking rate formula framework in setting their transmission rates. These rates are updated each January with forecasted information. If a given 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 amounts from customers within two years. If a given 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 two years.

The total return on equity currently allowed for Ameren Illinois’ and ATXI’s electric transmission service businesses is 10.82% and is subject to a FERC complaint case. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information. Recoverable transmission costs are included in the revenue requirement reconciliations, which result in corresponding adjustments to electric revenues, with no overall effect on net income. These recoverable transmission costs are included in other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes. A portion of the transmission costs included in those income statement rows are not recoverable based on the FERC formula rate framework.

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 and timing of 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 months ended March 31, 2017 and 2016:

	Three Months
	2017		2016
Net income attributable to Ameren common shareholders	$	102	$	105
Earnings per common share – basic and diluted	0.42		0.43

Net income attributable to Ameren common shareholders decreased $3 million, or 1 cent per diluted share, in the first quarter of 2017 compared with the year-ago period. The decrease between periods was partially due to a decrease in net income of $18 million for activity not reported as part of a segment, primarily at Ameren (parent). Additionally, net income decreased at Ameren Missouri and Ameren Illinois Natural Gas by $9 million and $2 million, respectively. The decrease was mostly offset by increases in net income of $19 million and $7 million at Ameren Illinois Electric Distribution and Ameren Transmission, respectively.

Compared with 2016, 2017 earnings per diluted share were unfavorably affected by:

• an increase in the effective tax rate primarily due to a decrease in the income tax benefit recorded at Ameren (parent) related to share-based compensation (7 cents per share);

• decreased demand primarily at Ameren Missouri due to milder winter temperatures in 2017 (estimated at 3 cents per share); and

• increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri resulting from additional electric property, plant, and equipment, as multiple projects were completed in 2016 (2 cents per share).

Compared with 2016, 2017 earnings per diluted share were favorably affected by:

• a change in the method used to recognize Ameren Illinois Electric Distribution’s interim period revenue, in connection with the decoupling provisions of the FEJA as discussed in Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report (8 cents per share);

• increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base (2 cents per share);

• increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional rate base investment as well as a higher recognized return on equity (1 cent per share); and

• decreased other operations and maintenance expenses not subject to riders, regulatory tracking mechanisms, or formula ratemaking, primarily at Ameren Missouri (1 cent per share).

The cents per share information presented is based on the average diluted shares outstanding in the first quarter of 2016. Pretax amounts have been presented net of income taxes, using Ameren’s 2016 statutory tax rate of 39%. For additional details regarding the Ameren Companies’ results of operations, including explanations of Electric and Natural Gas Margins, Other Operations and Maintenance Expenses, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income and Expenses, Interest Charges, and Income Taxes, see the major headings below.

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Below is Ameren’s table of income statement components by segment for the three months ended March 31, 2017 and 2016:

	Ameren Missouri			Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas			Ameren Transmission			Other / Intersegment Eliminations			Total
Three Months 2017:
Electric margins	$	449		$	278		$	—		$	102		$	(9	)	$	820
Natural gas margins	24			—			154			—			—			178
Other operations and maintenance	(212		)	(131		)	(53		)	(16		)	7			(405		)
Depreciation and amortization	(133		)	(59		)	(14		)	(14		)	(1		)	(221		)
Taxes other than income taxes	(75		)	(18		)	(21		)	(1		)	(3		)	(118		)
Other income (expense)	10			(1		)	(2		)	—			(1		)	6
Interest charges	(54		)	(18		)	(10		)	(15		)	(2		)	(99		)
Income taxes	(3		)	(20		)	(21		)	(22		)	9			(57		)
Net income	6			31			33			34			—			104
Noncontrolling interests – preferred stock dividends	(1		)	(1		)	—			—			—			(2		)
Net income attributable to Ameren common shareholders	$	5		$	30		$	33		$	34		$	—		$	102
Three Months 2016:
Electric margins	$	449		$	237		$	—		$	83		$	(8	)	$	761
Natural gas margins	26			—			154			—			—			180
Other operations and maintenance	(212		)	(130		)	(52		)	(15		)	9			(400		)
Depreciation and amortization	(127		)	(54		)	(14		)	(10		)	(2		)	(207		)
Taxes other than income taxes	(73		)	(16		)	(21		)	(1		)	(3		)	(114		)
Other income (expense)	13			—			(1		)	1			—			13
Interest charges	(52		)	(18		)	(9		)	(13		)	(3		)	(95		)
Income taxes	(9		)	(7		)	(22		)	(18		)	25			(31		)
Net income	15			12			35			27			18			107
Noncontrolling interests – preferred stock dividends	(1		)	(1		)	—			—			—			(2		)
Net income attributable to Ameren common shareholders	$	14		$	11		$	35		$	27		$	18		$	105

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Below is Ameren Illinois' table of income statement components by segment for the three months ended March 31, 2017 and 2016:

	Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas			Ameren Illinois Transmission			Total
Three Months 2017:
Electric and natural gas margins	$	278		$	154		$	60		$	492
Other operations and maintenance	(131		)	(53		)	(13		)	(197		)
Depreciation and amortization	(59		)	(14		)	(10		)	(83		)
Taxes other than income taxes	(18		)	(21		)	(1		)	(40		)
Other income (expense)	(1		)	(2		)	—			(3		)
Interest charges	(18		)	(10		)	(9		)	(37		)
Income taxes	(20		)	(21		)	(11		)	(52		)
Net income	31			33			16			80
Preferred stock dividends	(1		)	—			—			(1		)
Net income attributable to common shareholder	$	30		$	33		$	16		$	79
Three Months 2016:
Electric and natural gas margins	$	237		$	154		$	51		$	442
Other operations and maintenance	(130		)	(52		)	(12		)	(194		)
Depreciation and amortization	(54		)	(14		)	(9		)	(77		)
Taxes other than income taxes	(16		)	(21		)	(1		)	(38		)
Other income (expense)	—			(1		)	1			—
Interest charges	(18		)	(9		)	(8		)	(35		)
Income taxes	(7		)	(22		)	(9		)	(38		)
Net income	12			35			13			60
Preferred stock dividends	(1		)	—			—			(1		)
Net income attributable to common shareholder	$	11		$	35		$	13		$	59

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Electric and Natural Gas Margins

The following table presents the favorable (unfavorable) variations by Ameren segment for electric and natural gas margins for the first quarter of 2017, compared with the year-ago period. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as natural gas revenues less natural 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 they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

	Ameren Missouri			Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas			Ameren Transmission(a)		Other / Intersegment Eliminations			Ameren
Electric revenue change:
Effect of weather (estimate)(b)	$	(20	)	$	6		$	—		$	—	$	—		$	(14	)
Base rates (estimate)(c)	—			6			—			19		—			25
FEJA impact on IEIMA	—			32			—			—		—			32
Sales volume (excluding the New Madrid Smelter and estimated effect of weather)	(2		)	—			—			—		—			(2		)
New Madrid Smelter revenues	(8		)	—			—			—		—			(8		)
Off-system sales	79			—			—			—		—			79
Other	5			(4		)	—			—		—			1
Cost recovery mechanisms – offset in fuel and purchased power:(d)
Power supply costs	—			(6		)	—			—		—			(6		)
Transmission services recovery mechanism	—			(3		)	—			—		—			(3		)
Recovery of FAC under-recovery	(11		)	—			—			—		—			(11		)
Other cost recovery mechanisms:(e)
Bad debt, energy efficiency programs, and environmental remediation cost riders	—			2			—			—		—			2
Gross receipts tax	1			—			—			—		—			1
MEEIA program costs	8			—			—			—		—			8
Total electric revenue change	$	52		$	33		$	—		$	19	$	—		$	104
Fuel and purchased power change:
Energy costs (excluding the New Madrid Smelter and estimated effect of weather)	$	(79	)	$	—		$	—		$	—	$	—		$	(79	)
New Madrid Smelter energy costs	8			—			—			—		—			8
Effect of weather (estimate)(b)	6			(3		)	—			—		—			3
Other	2			2			—			—		(1		)	3
Cost recovery mechanisms – offset in electric revenue:(d)
Power supply costs	—			6			—			—		—			6
Transmission services recovery mechanism	—			3			—			—		—			3
Recovery of FAC under-recovery	11			—			—			—		—			11
Total fuel and purchased power change	$	(52	)	$	8		$	—		$	—	$	(1	)	$	(45	)
Net change in electric margins	$	—		$	41		$	—		$	19	$	(1	)	$	59
Natural gas revenue change:
Effect of weather (estimate)(b)	$	(5	)	$	—		$	—		$	—	$	—		$	(5	)
Other	(1		)	—			—			—		—			(1		)
Purchased natural gas costs – offset in natural gas purchased for resale:(d)	3			—			(21		)	—		—			(18		)
Other cost recovery mechanisms:(e)
Bad debt, energy efficiency programs, and environmental remediation cost riders	—			—			1			—		—			1
Gross receipts tax	—			—			(1		)	—		—			(1		)
Total natural gas revenue change	$	(3	)	$	—		$	(21	)	$	—	$	—		$	(24	)
Natural gas purchased for resale change:
Effect of weather (estimate)(b)	$	4		$	—		$	—		$	—	$	—		$	4
Purchased natural gas costs – offset in natural gas revenue:(d)	(3		)	—			21			—		—			18
Total natural gas purchased for resale change	$	1		$	—		$	21		$	—	$	—		$	22
Net change in natural gas margins	$	(2	)	$	—		$	—		$	—	$	—		$	(2	)

(a) Includes an increase in transmission margins of $9 million at Ameren Illinois.

(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; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories. Beginning in 2017, FEJA eliminated the impact of weather on Ameren Illinois Electric Distribution’s electric margins.

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(c) For Ameren Illinois Electric Distribution and Ameren Transmission, base rates include increases or decreases to operating revenues related to the revenue requirement reconciliation adjustment under formula rates.

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

(e) 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.

Ameren

Ameren's electric margins increased $59 million, or 8%, in the first quarter of 2017, compared with the year-ago period, primarily because of increased margins at Ameren Illinois Electric Distribution and Ameren Transmission. Ameren's natural gas margins were comparable between periods.

Ameren Transmission

Ameren Transmission's margins increased $19 million, or 23%, in the first quarter of 2017 compared with the year-ago period. The increase in margins was primarily due to capital investment, which increased rate base by 18%, as well as higher recoverable costs in the first quarter of 2017, compared with the year-ago period, under forward-looking formula ratemaking.

Ameren Missouri

Ameren Missouri's electric margins were comparable between periods. Decreased retail sales volumes, largely due to milder winter temperatures, were offset by increased MEEIA program cost revenues and other revenues. Ameren Missouri’s natural gas margins were comparable between periods.

Ameren Illinois

Ameren Illinois' electric margins increased by $50 million, or 17%, in the first quarter of 2017 compared with the year-ago period, driven by increases in Ameren Illinois Electric Distribution ($41 million) and Ameren Illinois Transmission ($9 million) margins. Ameren Illinois Natural Gas’ margins were comparable between periods.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins increased $41 million, or 17%, in the first quarter of 2017, compared with the year-ago period. The following items had a favorable effect on Ameren Illinois Electric Distribution’s margins in the first quarter of 2017, compared with the year-ago period:

• A change in the method used to recognize interim period revenue, in connection with the decoupling provisions of the FEJA, which increased margins by $32 million. This change will not impact annual earnings. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information on FEJA and IEIMA.

• Revenues increased by $6 million, primarily due to increased rate base and a higher 30-year United States Treasury bond yield under formula ratemaking.  

• The absence of the impact of warmer-than-normal 2016 weather and the decoupling of revenues in 2017, which increased margins by $3 million 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 (+$6 million) and the effect of weather (estimate) on fuel and purchased power (-$3 million) in the Electric and Natural Gas Margins table above.

Ameren Illinois Transmission

Ameren Illinois Transmission's margins increased $9 million, or 18%, in the first quarter of 2017 compared with the year-ago period. The increase in margins was primarily due to capital investment, which increased rate base by 22%, as well as higher recoverable costs in the first quarter of 2017, compared with the year-ago period, under forward-looking formula ratemaking.

Other Operations and Maintenance Expenses

Ameren

Other operations and maintenance expenses were $5 million higher in the first quarter of 2017, compared with the year-ago period, as discussed below.

Ameren Transmission

Other operations and maintenance expenses were comparable in the first quarter of 2017 with the year-ago period.

Ameren Missouri

Other operations and maintenance expenses were comparable in the first quarter of 2017 with the year-ago period. Increased MEEIA customer energy efficiency program costs were offset by decreased refueling and maintenance outage costs at the Callaway energy center and increased MTM gains resulting from changes in the market value of company-owned life insurance. Electric revenues related to MEEIA program costs increased by a corresponding amount, with no overall effect on net income.

Ameren Illinois

Other operations and maintenance expenses were $3 million higher in the first quarter of 2017, compared with the year-ago period, primarily because of higher estimated litigation costs at Ameren Illinois Electric Distribution and higher pension costs at each Ameren Illinois segment, caused by changes in actuarial assumptions and the performance of plan assets. Other operations and maintenance expenses were comparable between periods at each Ameren Illinois segment.

Depreciation and Amortization

Ameren

Depreciation and amortization expenses increased $14

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million in the first quarter of 2017, compared with the year-ago period, as discussed below.

Ameren Transmission

Depreciation and amortization expenses increased $4 million, primarily because of additional ATXI property, plant, and equipment.

Ameren Missouri

Depreciation and amortization expenses increased $6 million, primarily because of additional electric property, plant, and equipment, as multiple projects were completed in 2016.

Ameren Illinois

Depreciation and amortization expenses increased $6 million, primarily because of increased expenses at Ameren Illinois Electric Distribution, as discussed below. Depreciation and amortization expenses were comparable between periods at Ameren Illinois Natural Gas and Ameren Illinois Transmission.

Ameren Illinois Electric Distribution

Depreciation and amortization expenses increased $5 million, primarily because of additional property, plant, and equipment.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $4 million at Ameren in the first quarter of 2017, compared with the year-ago period, primarily because of higher property taxes at Ameren Missouri and Ameren Illinois Electric Distribution. Taxes other than income taxes were comparable between periods at Ameren Illinois, as well as the Ameren Transmission, Ameren Illinois Natural Gas, and Ameren Illinois Transmission segments.

Other Income and Expenses

Ameren

Other income, net of expenses, decreased $7 million in the first quarter of 2017, compared with the year-ago period, as discussed below. See Note 5 – Other Income and Expenses under Part I, Item 1, of this report for additional information.

Ameren Transmission

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

Ameren Missouri

Other income, net of expenses, decreased $3 million, primarily because of a decrease in the allowance for equity funds used during construction, as multiple electric projects were completed in 2016.

Ameren Illinois

Other income, net of expenses, decreased $3 million, primarily because of lower interest income on IEIMA revenue requirement reconciliation regulatory assets and a decrease in the allowance for equity funds used during construction, resulting from lower eligible construction work in progress balances. Other income, net of expenses, was comparable between periods at each Ameren Illinois segment.

Interest Charges

Interest charges increased $4 million at Ameren in the first quarter of 2017, compared with the year-ago period, primarily because of a decrease in the allowance for borrowed funds used during construction at Ameren Missouri and Ameren Transmission, resulting from lower eligible construction work in progress balances. Interest charges were comparable between periods at Ameren Illinois and each of its segments.

Income Taxes

The following table presents effective income tax rates for the three months ended March 31, 2017 and 2016:

	Three Months(a)
	2017		2016
Ameren	35	%	22	%
Ameren Transmission	39	%	40	%
Ameren Missouri	38	%	38	%
Ameren Illinois	39	%	39	%
Ameren Illinois Electric Distribution	40	%	38	%
Ameren Illinois Natural Gas	39	%	39	%
Ameren Illinois Transmission	39	%	38	%

(a) Estimate of the annual effective tax rate adjusted to reflect the tax effect of items discrete to the first quarter.

Ameren

The effective tax rate was higher in the first quarter of 2017, compared with the year-ago period, primarily because of a decrease in the recognition of tax benefits associated with share-based compensation.

Ameren Transmission

The effective tax rate was comparable between periods.

Ameren Missouri

The effective tax rate was comparable between periods.

Ameren Illinois

The effective tax rate was comparable between periods at Ameren Illinois. The effective tax rate was higher at Ameren Illinois Electric Distribution, as discussed below. The effective tax rate was comparable between periods at Ameren Illinois Natural Gas and Ameren Illinois Transmission.

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Ameren Illinois Electric Distribution

The effective tax rate was higher in the first quarter of 2017, compared with the year-ago period, primarily because of the decreased effect of tax benefits on higher pretax income in the current year from certain depreciation differences on property-related items, tax credits, and company-owned life insurance.

LIQUIDITY AND CAPITAL RESOURCES

Collections from our tariff-based revenues are our principal source of cash provided by 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 provided by operating activities, we use available cash, borrowings under the Credit Agreements, commercial paper issuances, or, in the case of Ameren Missouri and Ameren Illinois, short-term intercompany borrowings to support normal operations and temporary capital requirements. We may reduce our short-term borrowings with cash provided by operations or, at our discretion, with long-term borrowings, or, in the case of

Ameren Missouri and Ameren Illinois, with 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 primarily with cash provided by operating activities and short-term and long-term debt issuances so that we maintain an equity ratio around 50%, assuming constructive regulatory environments.

The use of cash provided by 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 March 31, 2017, for the Ameren Companies. The working capital deficit as of March 31, 2017, was primarily the result of current maturities of long-term debt and our decision to finance our businesses with lower-cost commercial paper issuances. With the credit capacity available under the Credit Agreements, the Ameren Companies had access to $1.2 billion of liquidity atMarch 31, 2017.

The following table presents net cash provided by (used in) operating, investing, and financing activities for the three months ended March 31, 2017 and 2016:

	Net Cash Provided By Operating Activities							Net Cash Used In Investing Activities									Net Cash Provided by (Used In) Financing Activities
	2017		2016		Variance			2017			2016			Variance			2017			2016			Variance
Ameren(a)	$	331	$	349	$	(18	)	$	(539	)	$	(510	)	$	(29	)	$	207		$	(118	)	$	325
Ameren Missouri	93		169		(76		)	(68		)	(170		)	102			(25		)	(198		)	173
Ameren Illinois	212		229		(17		)	(227		)	(269		)	42			15			(31		)	46

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

Cash Flows from Operating Activities

Our cash provided by operating activities is affected by fluctuations of trade accounts receivable, inventories, and accounts and wages payable, among other things, as well as the unique regulatory environment for each of our businesses. Substantially all expenditures related to fuel, purchased power, and natural gas purchased for resale are recovered from customers through rate adjustment mechanisms, which may be adjusted without a traditional rate proceeding. Similar regulatory mechanisms exist for certain operating expenses that can also affect the timing of cash provided by operating activities. The timing of cash paid for costs recoverable under our regulatory mechanisms differs from the recovery period of those costs. Additionally, the seasonality of our electric and natural gas businesses, primarily caused by changes in customer demand due to weather, significantly impact the amount and timing of our cash provided by operating activities.

Ameren

Ameren’s cash from operating activities decreased$18 million in the first quarter of 2017, compared to the year-ago period. The following items contributed to the decrease:

• The absence of a $42 million insurance receipt at Ameren Missouri related to the Taum Sauk breach received in 2016.

• Refunds of $21 million associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report.

• An $11 million increase in natural gas held in storage caused primarily by reduced withdrawals as a result of milder winter temperatures compared with the prior year.

• An $8 million decrease in cash associated with the recovery of Ameren Illinois' IEIMA revenue requirement reconciliation adjustments. The 2015 revenue requirement reconciliation adjustment, which is being recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.

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

• A $36 million increase 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.

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• An $18 million decrease in Ameren Missouri’s coal inventory as a result of increased generation levels.

Ameren Missouri

Ameren Missouri’s cash from operating activities decreased$76 million in the first quarter of 2017, compared to the year-ago period. The following items contributed to the decrease:

• The absence of a $42 million insurance receipt related to the Taum Sauk breach received in 2016.

• A $17 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.

• An increase of $14 million in income tax payments paid to Ameren (parent) pursuant to the tax allocation agreement, primarily related to the timing of payments.

An $18 million decrease in coal inventory as a result of increased generation levels partially offset the decrease in Ameren Missouri’s cash from operating activities between periods.

Ameren Illinois

Ameren Illinois’ cash from operating activities decreased$17 million in the first quarter of 2017, compared to the year-ago period. The following items contributed to the decrease:

• Refunds of $17 million associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report.

• A $10 million increase in natural gas held in storage caused primarily by reduced withdrawals as a result of milder winter temperatures compared with the prior year.

• An $8 million decrease in cash associated with the recovery of IEIMA revenue requirement reconciliation adjustments. The 2015 revenue requirement reconciliation adjustment, which is being recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.

• An $8 million increase in interest payments, primarily due to an increase in the average outstanding debt.

• A $5 million increase in expenditures for customer energy efficiency programs compared with amounts collected from customers.

• A $4 million increase in payments for purchased power compared with amounts collected from customers.

Ameren Illinois’ decrease in cash from operating activities was partially offset by a $48 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, offset by the change in customer receivable balances.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities increased$29 million in the first three months of 2017, compared with the year-

ago period. Capital expenditures increased$8 million primarily as a result of the activity at Ameren Missouri and Ameren Illinois, as discussed below, offset by a $27 million decrease in ATXI’s capital expenditures which primarily related to the Illinois Rivers project.

Ameren Missouri’s cash used in investing activities decreased$102 million in the first three months of 2017, compared with the year-ago period, due to a $125 million increase in the return of money pool advances.This was partially offset by an $18 million increase in capital expenditures primarily related to electric distribution system reliability and energy center projects as well as a $6 million increase in nuclear fuel expenditures.

Ameren Illinois’ cash used in investing activities decreased$42 million due to a $58 million decrease in money pool advances partially offset by a $16 million increase in capital expenditures primarily related to electric distribution and transmission system reliability and substation upgrades.

Cash Flows from Financing Activities

Cash provided by, or used in, financing activities is 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 financing activities provided net cash of $207 million during the first three months of 2017, compared with using net cash of $118 million during the year-ago period. An increase in short-term debt issuances as well as the absence in 2017 of long-term debt maturities resulted in $336 million more cash provided by financing activities in the first three months of 2017, compared with the year-ago period.

Ameren Missouri’s cash used in financing activities decreased$173 million in the first three months of 2017, compared with the year-ago period. During the first three months of 2017, cash paid to Ameren (parent) as dividends, net of capital contributions from parent, decreased $42 million, compared to the year ago period. Additionally, Ameren Missouri repaid $260 million in long-term debt in 2016, compared with no maturities in 2017. The decrease was partially offset by $129 million less cash provided by short-term debt in the first three months of 2017, compared with the year-ago period.

Ameren Illinois’ financing activities provided cash of $15 million during the first three months of 2017, compared to using cash of $31 million during the same period in 2016. Ameren Illinois did not pay Ameren (parent) dividends during the first three months of 2017, compared with $30 million in dividends paid in the year-ago period. Additionally, cash provided by short-term debt increased $17 million in 2017, compared with the year-ago period.

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

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Credit Facility Borrowings and Liquidity

The liquidity needs of Ameren, Ameren Missouri, and Ameren Illinois are typically supported through the use of available cash, commercial paper issuances, short-term intercompany borrowings, or drawings under the Credit Agreements. See Note 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information on the 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 March 31, 2017:

Amerenand Ameren Missouri:
Missouri Credit Agreement – borrowing capacity	$	1,000
Less: Ameren (parent) commercial paper outstanding	472
Less: Ameren Missouri commercial paper outstanding	36
Missouri Credit Agreement – credit available	492
Ameren and Ameren Illinois:
Illinois Credit Agreement – borrowing capacity	1,100
Less: Ameren (parent) commercial paper outstanding	338
Less: Ameren Illinois commercial paper outstanding	68
Less: Letters of credit	4
Illinois Credit Agreement – credit available	690
Total Credit Available	$	1,182
Cash and cash equivalents	8
Total Liquidity	$	1,190

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. 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. Commercial paper issuances were thus preferred to credit facility borrowings as a source of third-party short-term debt.

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 will access funds from the utility money pool, the Credit Agreements, or the commercial paper programs depending on which option offers the lowest interest rates.

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

Long-term Debt and Equity

The Ameren Companies did not issue any common stock during the first three months of 2017 or 2016. In March 2016, Ameren Missouri received cash capital contributions of $38 million from Ameren (parent).

Indebtedness Provisions and Other Covenants

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

At March 31, 2017, the Ameren Companies were in compliance with the provisions and covenants contained 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

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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 it 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 April 28, 2017, Ameren’s board of

directors declared a quarterly common stock dividend of 44 cents per share payable on June 30, 2017, to shareholders of record on June 14, 2017.

See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of the Form 10-K for additional discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At March 31, 2017, 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 three months ended March 31, 2017 and 2016:

	Three Months
	2017		2016
Ameren Missouri	$	60	$	140
Ameren Illinois	—		30
Ameren	107		103

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 March 31, 2017, 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 $3,824 million, $2,340 million, and $1,418 million, respectively.

Off-Balance-Sheet Arrangements

At March 31, 2017, 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.

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.

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Collateral Postings

Any 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 March 31, 2017. A sub-investment-grade issuer or senior unsecured debt rating (whether below “BBB-” from S&P or below “Baa3” from Moody’s) at March 31, 2017, 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 $74 million, $44 million, and $30 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at March 31, 2017, if market prices were 15% higher or lower than March 31, 2017 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 could be required to post an immaterial amount, compared to each company’s liquidity, of collateral or other assurances for certain trade 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, while also advocating for responsible energy policies. We are seeking to align our overall spending, both operating and capital, with economic conditions and with regulatory frameworks established by our regulators and to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We are focused on minimizing the gap between allowed and earned returns on equity and intend to allocate capital resources to our business opportunities that we expect to offer the most attractive risk-adjusted return potential.

As a part of Ameren's strategic plan, we are pursuing projects to meet our customer energy needs and to improve electric and natural gas system reliability, safety, and security within our service territories, as well as evaluating competitive electric transmission investment opportunities outside of these territories, including investments outside of MISO as they arise. Additionally, Ameren Missouri will make investments over time that will enable it to transition to a more diverse energy portfolio.

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 2017 and beyond.

Operations

• Ameren continues to invest in FERC-regulated electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The Illinois Rivers project involves the construction of a transmission line from western Indiana across the state of Illinois to eastern Missouri. Construction activities for the Illinois Rivers project are continuing on schedule and 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. Construction activities for the Spoon River project are continuing on schedule and the project is expected to be completed in 2018. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding the Mark Twain project and its approval process. The total investment in all three projects is expected to be more than $575 million from 2017 through 2019. Ameren Illinois expects to invest $2.2 billion in electric transmission assets from 2017 through 2021 to replace aging infrastructure and improve reliability.

• Both Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Based on the rates that became effective on January 1, 2017, and the currently allowed 10.82% return on common equity, the 2017 revenue requirement for Ameren Illinois’ electric transmission business is $258 million. The 2017 revenue requirement represents a $33 million increase over the revised 2016 revenue requirement, which became effective in September 2016, and was based on a 10.82% return on common equity. These January 2017 rates reflect a capital structure comprised of 51.6% common equity and a projected average rate base of $1.4 billion. Based on the rates that became effective on January 1, 2017, and the currently allowed 10.82% return on equity, the 2017 revenue requirement for ATXI’s electric transmission business is $171 million. The 2017 revenue requirement represents a $44 million increase over the revised 2016 revenue requirement, which became effective in September 2016, and was based on a 10.82% return on common equity. These January 2017 rates reflect a capital structure comprised of 56.3% common equity and a projected average rate base of $1.1 billion, reflecting additional investment in the Illinois Rivers project.

• The return on common equity was the subject of two FERC complaint proceedings, the November 2013 complaint case and the February 2015 complaint case, that each challenged the allowed base return on common equity for MISO transmission owners, including Ameren Illinois and ATXI. In September 2016, the FERC issued a final order in the November 2013 complaint case, which lowered the allowed base return on common equity for the 15-month period of November 2013 to February 2015 to 10.32%, or a 10.82% total allowed return on common equity with the

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inclusion of the 50 basis point incentive adder for participation in an RTO. The order required customer refunds, with interest, to be issued for that 15-month period. Refunds for the November 2013 complaint case were issued in the first quarter of 2017. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case, which if approved by the FERC, would lower the allowed base return on common equity for the 15-month period of February 2015 to May 2016 to 9.70%, or a 10.20% total allowed return on equity with the inclusion of the 50 basis point incentive adder for participation in an RTO and require customer refunds, with interest, for that 15-month period. The timing of the issuance of the final order in the February 2015 complaint case, which will prospectively replace the current 10.82% allowed return on equity, is uncertain for two reasons. First, at this time the FERC lacks a quorum of three commissioners. Second, the United States Court of Appeals for the District of Columbia recently vacated and remanded to the FERC an order in a separate case in which the FERC established the allowed base return on common equity methodology used in the two MISO complaint cases described above. A 50 basis point reduction in the FERC-allowed base return on common equity would reduce Ameren's and Ameren Illinois' annual earnings by an estimated $7 million and $4 million, respectively, based on each company’s 2017 projected rate base. Ameren and Ameren Illinois recorded current regulatory liabilities on their respective March 31, 2017 balance sheets, representing their estimate of the expected refunds.

• In March 2017, the MoPSC issued an order approving a unanimous stipulation and agreement in Ameren Missouri’s July 2016 regulatory rate review. The order resulted in a $3.4 billion revenue requirement, which is a $92 million increase in Ameren Missouri’s annual revenue requirement for electric service, compared to its prior revenue requirement established in the MoPSC's April 2015 electric rate order. The new rates, base level of expenses, and amortizations became effective on April 1, 2017. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs decrease by $54 million from the base level established in the MoPSC's April 2015 electric rate order. Changes in amortizations and the base level of expenses for the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, reduce expenses by $26 million from the base levels established in the MoPSC's April 2015 electric rate order.

• Illinois law provides for an annual reconciliation of the electric distribution revenue requirement necessary to reflect the actual costs incurred and investment return in a given year with the revenue requirement that was reflected in customer rates for that year. Consequently, Ameren Illinois' 2017 electric distribution service revenues will be based on its 2017 actual recoverable costs, rate base, and return on common equity as calculated under the Illinois performance-based formula ratemaking framework. The 2017 revenue requirement is expected to be higher than the 2016 revenue

requirement because of an expected increase in recoverable costs, expected rate base growth of 5%, and an expected increase in the monthly average of United States treasury bonds. The 2017 revenue requirement reconciliation is expected to result in a regulatory asset that will be collected from customers in 2019. A 50 basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $7 million change in Ameren's and Ameren Illinois' net income, based on Ameren Illinois’ 2017 projected year-end rate base.

• In April 2017, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for 2018 rates. Pending ICC approval, this update filing will result in a$16 milliondecrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2018. These rates will affect Ameren Illinois' cash receipts during 2018, but will not determine its electric distribution service operating revenues, which will instead be based on its 2018 actual recoverable costs, rate base, and return on common equity as calculated under the Illinois performance-based formula ratemaking framework. An ICC decision on the revenue requirement used for 2018 rates is expected by December 2017.

• Beginning in 2017, the FEJA provides that Ameren Illinois recovers, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes. In connection with the decoupling provisions of the FEJA, Ameren Illinois changed its method used to recognize its interim period revenue. Ameren Illinois will now recognize revenues consistent with the timing of incurred electric distribution recoverable costs and recognize revenue associated with the expected return on its rate base ratably over the year. As a result of this change in recognition of the interim period revenue for the IEIMA formula rate framework, as modified by FEJA, Ameren Illinois expects quarterly year-over-year increases to earnings in 2017 in comparison to 2016 for the first, second, and fourth quarters and a decrease to earnings in the third quarter. The change in interim period revenue recognition will not impact 2017’s annual earnings.

• Beginning as early as June 2017, the FEJA will allow Ameren Illinois to earn a return on its electric energy efficiency program investments. Ameren Illinois electric energy efficiency investments will be deferred as a regulatory asset and will earn a return at the company’s weighted average cost of capital, with the equity return based on the monthly average yield of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ return on electric energy efficiency investments can also be increased or decreased by 200 basis points based on the achievement of annual energy savings goals. Based on a formula provided in the act, Ameren Illinois estimates it can annually invest up to $100 million from 2018 through 2021, up to $107 million annually

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from 2022 through 2025, and up to $114 million annually from 2026 through 2030. The ICC has the ability to lower the electric energy efficiency saving goals if there are insufficient cost effective measures available or if achieving the savings goals would require investment levels that exceed the formula amounts shown above. The electric energy efficiency program investments and the return on those investments will be recovered through a rider, and will not be included in the IEIMA formula rate process.

• In 2018, Ameren Illinois expects to file for a natural gas regulatory rate review with the ICC. Ameren Illinois’ current allowed return on equity for natural gas delivery service is 9.60%, with a capital structure of 50% common equity, a rate base of $1.2 billion, and a 2016 future test year.

• The next scheduled refueling and maintenance outage at Ameren Missouri’s Callaway energy center will be in fall 2017. Ameren Missouri expects to incur $32 million of maintenance expenses, which approximates the cost of the spring 2016 outage. 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 legislative solutions, as necessary, 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 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 taxes, among other costs.

For additional information regarding recent rate orders, lawsuits, the Westinghouse bankruptcy filing, and pending requests filed with state and federal regulatory commissions, see Note 2 – Rate and Regulatory Matters and Note 10 – Callaway Energy Center under Part I, Item 1, of this report and Note 2 –

Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K.

Liquidity and Capital Resources

• Through 2021, 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 distribution systems. We estimate that we will invest in total up to $11.2 billion (Ameren Missouri – up to $4.2 billion; Ameren Illinois – up to $6.4 billion; ATXI – up to $0.6 billion) of capital expenditures during the period from 2017 through 2021.

• Environmental regulations, including those related to CO₂ emissions, or other actions taken by the EPA could result in significant increases in capital expenditures and operating costs. Certain of these regulations are being challenged through litigation, or are being reviewed by the EPA, so their ultimate implementation, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing environmental regulations could result in significant capital expenditures and increased operating costs for Ameren and Ameren Missouri. These costs 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 natural 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 customer rates.

• Ameren Missouri files a nonbinding integrated resource plan with the MoPSC every three years and will file its next plan in October 2017. 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 diverse energy portfolio in Missouri, including coal, solar, wind, natural gas, hydro and nuclear power. The plan involves expanding renewable generation, retiring coal-fired generation as those energy centers reach the end of their useful lives, expanding customer 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 2021, subject to a 364-day repayment term in the case of Ameren Missouri and Ameren Illinois. See Note 4 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information regarding the Credit Agreements. By the end of 2018, $803 million and $707 million of senior secured notes are scheduled to mature at

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Ameren Missouri and Ameren Illinois, respectively. Ameren Missouri and Ameren Illinois expect to refinance these senior secured notes. In addition, the Ameren Companies may refinance a portion of their outstanding short-term debt with long-term debt in 2017. 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 which allows for an acceleration of deductions for tax purposes at a rate of 50% through 2017. The rate will be reduced to 40% in 2018 and to 30% in 2019. Bonus depreciation will be phased out in 2020 unless a new law is enacted. 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 the Ameren Companies will vary based on investment levels at each company.

• As of March 31, 2017, Ameren had $598 million in tax benefits from federal and state net operating loss carryforwards (Ameren Missouri – $41 million and Ameren Illinois – $155 million) and $131 million in federal and state income tax credit carryforwards (Ameren Missouri – $29 million and Ameren Illinois – $1 million). In addition, Ameren has $34 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 through 2019 and Ameren Illinois until 2021. Based on existing tax laws, 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 Ameren 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.

With the exception of the following, 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. In the first quarter of 2017, Ameren Missouri’s supplier of nuclear fuel assemblies, Westinghouse, filed a voluntary petition for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. At this time, Ameren and Ameren Missouri believe the restructuring proceeding will not affect Westinghouse’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 Note 10 – Callaway Energy Center under Part I, Item 1, of this report for additional information. 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 months ended March 31, 2017. We use various methods to determine the

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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.

	Ameren Missouri			Ameren Illinois			Ameren
Fair value of contracts at beginning of period, net	$	(4	)	$	(180	)	$	(184	)
Contracts realized or otherwise settled during the period	(2		)	2			—
Fair value of new contracts entered into during the period	—			(1		)	(1		)
Other changes in fair value	(1		)	(25		)	(26		)
Fair value of contracts outstanding at end of period, net	$	(7	)	$	(204	)	$	(211	)

The following table presents maturities of derivative contracts as of March 31, 2017, 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
Ameren Missouri:
Level 1	$	(3	)	$	—		$	—		$	—		$	(3	)
Level 2(a)	(3		)	(5		)	—			—			(8		)
Level 3(b)	4			—			—			—			4
Total	$	(2	)	$	(5	)	$	—		$	—		$	(7	)
Ameren Illinois:
Level 1	$	1		$	—		$	—		$	—		$	1
Level 2(a)	(2		)	(7		)	—			—			(9		)
Level 3(b)	(12		)	(28		)	(29		)	(127		)	(196		)
Total	$	(13	)	$	(35	)	$	(29	)	$	(127	)	$	(204	)
Ameren:
Level 1	$	(2	)	$	—		$	—		$	—		$	(2	)
Level 2(a)	(5		)	(12		)	—			—			(17		)
Level 3(b)	(8		)	(28		)	(29		)	(127		)	(192		)
Total	$	(15	)	$	(40	)	$	(29	)	$	(127	)	$	(211	)

(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 March 31, 2017, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on those evaluations, as of March 31, 2017, 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,

49

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 Illinois’ annual electric distribution service formula rate update filed with the ICC in April 2017;

• ATXI’s 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 road crossings in the counties where the Mark Twain transmission project will be constructed;

• the February 2015 complaint case filed with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff;

• litigation against Ameren Missouri related to the EPA Clean Air Act;

• 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 (a)	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
January 1 – January 31, 2017	12,030	52.55		—	—
February 1 – February 28, 2017	—	—		—	—
March 1 – March 31, 2017	446,934	54.65		—	—
Total	458,964	$	54.59	—	—

(a) The January shares of Ameren common stock 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. The March shares of Ameren common stock were purchased in open-market transactions pursuant to the 2014 Incentive Plan in satisfaction of Ameren’s obligation to distribute shares of common stock for vested performance units. Ameren does not have any publicly announced equity securities repurchase plans or programs.

Ameren Missouri and Ameren Illinois did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from January 1, 2017 to March 31, 2017.

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ITEM 6. EXHIBITS.

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

Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
Statement re: Computation of Ratios
12.1	Ameren	Ameren's Statement of Computation of Ratio of Earnings to Fixed Charges
12.2	Ameren Missouri	Ameren Missouri's Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.3	Ameren Illinois	Ameren Illinois’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
Rule 13a-14(a) / 15d-14(a) Certifications
31.1	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren
31.2	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren
31.3	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Missouri
31.4	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Missouri
31.5	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois
31.6	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois
Section 1350 Certifications
32.1	Ameren	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren
32.2	Ameren Missouri	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri
32.3	Ameren Illinois	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Illinois
Interactive Data Files
101.INS	Ameren Companies	XBRL Instance Document
101.SCH	Ameren Companies	XBRL Taxonomy Extension Schema Document
101.CAL	Ameren Companies	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	Ameren Companies	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Ameren Companies	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	Ameren Companies	XBRL Taxonomy Extension Definition Document

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

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

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SIGNATURES

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

AMEREN CORPORATION

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

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

UNION ELECTRIC COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

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

AMEREN ILLINOIS COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

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

Date: May 5, 2017

52

EX-12.1

Exhibit 12.1

Ameren Corporation

Computation of Ratio of Earnings to Fixed Charges

(Thousands of Dollars, Except Ratio)

	Three Months Ended March 31,
	2017
Earnings available for fixed charges, as defined:
Net income from continuing operations attributable to Ameren Corporation	$	102,162
Tax expense based on income	56,838
Fixed charges excluding subsidiary preferred stock dividends tax adjustment	105,895
Earnings available for fixed charges, as defined	$	264,895
Fixed charges, as defined:
Interest expense on short-term and long-term debt	$	96,879
Estimated interest cost within rental expense	2,003
Amortization of net debt premium, discount, and expenses	5,402
Subsidiary preferred stock dividends	1,611
Adjust subsidiary preferred stock dividends to pretax basis	1,007
Total fixed charges, as defined	$	106,902
Consolidated ratio of earnings to fixed charges	2.48

EX-12.2

Exhibit 12.2

Union Electric Company

Computation of Ratio of Earnings to Fixed Charges and Combined

Fixed Charges and Preferred Stock Dividend Requirements

(Thousands of Dollars, Except Ratios)

	Three Months Ended March 31,
	2017
Earnings available for fixed charges, as defined:
Net income	$	5,392
Tax expense based on income	3,253
Fixed charges	57,581
Earnings available for fixed charges, as defined	$	66,226
Fixed charges, as defined:
Interest expense on short-term and long-term debt	$	55,137
Estimated interest cost within rental expense	920
Amortization of net debt premium, discount, and expenses	1,524
Total fixed charges, as defined	$	57,581
Ratio of earnings to fixed charges	1.15
Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends	$	855
Adjustment to pretax basis	516
	$	1,371
Combined fixed charges and preferred stock dividend requirements	$	58,952
Ratio of earnings to combined fixed charges and preferred stock dividend requirements	1.12

EX-12.3

Exhibit 12.3

Ameren Illinois Company

Computation of Ratio of Earnings to Fixed Charges and Combined

Fixed Charges and Preferred Stock Dividend Requirements

(Thousands of Dollars, Except Ratios)

	Three Months Ended March 31,
	2017
Earnings available for fixed charges, as defined:
Net income	$	79,938
Tax expense based on income	51,930
Fixed charges	38,296
Earnings available for fixed charges, as defined	$	170,164
Fixed charges, as defined:
Interest expense on short-term and long-term debt	$	33,885
Estimated interest cost within rental expense	1,067
Amortization of net debt premium, discount, and expenses	3,344
Total fixed charges, as defined	$	38,296
Ratio of earnings to fixed charges	4.44
Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends	$	756
Adjustment to pretax basis	491
	$	1,247
Combined fixed charges and preferred stock dividend requirements	$	39,543
Ratio of earnings to combined fixed charges and preferred stock dividend requirements	4.30

EX-31.1

Exhibit 31.1

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

OF PRINCIPAL EXECUTIVE OFFICER OF AMEREN CORPORATION

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

I, Warner L. Baxter, certify that:

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2017 of Ameren Corporation;

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

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

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

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

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

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

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

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

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

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

Date: May 5, 2017

 /s/ Warner L. Baxter

Warner L. Baxter

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

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

OF PRINCIPAL FINANCIAL OFFICER OF AMEREN CORPORATION

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

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

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2017 of Ameren Corporation;

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

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

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

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

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

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

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

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

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

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

Date: May 5, 2017

 /s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-31.3

Exhibit 31.3

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

OF PRINCIPAL EXECUTIVE OFFICER OF UNION ELECTRIC COMPANY

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

I, Michael L. Moehn, certify that:

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2017 of Union Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: May 5, 2017

 /s/ Michael L. Moehn

Michael L. Moehn

Chairman and President

(Principal Executive Officer)

EX-31.4

Exhibit 31.4

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

OF PRINCIPAL FINANCIAL OFFICER OF UNION ELECTRIC COMPANY

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

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

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2017 of Union Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: May 5, 2017

 /s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-31.5

Exhibit 31.5

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

OF PRINCIPAL EXECUTIVE OFFICER OF AMEREN ILLINOIS COMPANY

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

I, Richard J. Mark, certify that:

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2017 of Ameren Illinois Company;

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

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

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

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

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

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

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

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

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

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

Date: May 5, 2017

 /s/ Richard J. Mark

Richard J. Mark

Chairman and President

(Principal Executive Officer)

EX-31.6

Exhibit 31.6

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

OF PRINCIPAL FINANCIAL OFFICER OF AMEREN ILLINOIS COMPANY

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

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

1.    I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2017 of Ameren Illinois Company;

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

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

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

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

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

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

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

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

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

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

Date: May 5, 2017

 /s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.1

Exhibit 32.1

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

AMEREN CORPORATION

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

In connection with the report on Form 10-Q for the quarterly period ended March 31, 2017 of Ameren Corporation (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the "Form 10-Q”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 5, 2017

 
/s/ Warner L. Baxter

Warner L. Baxter

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

 /s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.2

Exhibit 32.2

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

UNION ELECTRIC COMPANY

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

In connection with the report on Form 10-Q for the quarterly period ended March 31, 2017 of Union Electric Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the "Form 10-Q"), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 5, 2017

 /s/ Michael L. Moehn

Michael L. Moehn

Chairman and President

(Principal Executive Officer)

 /s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.3

Exhibit 32.3

SECTION 1350 CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

AND THE PRINCIPAL FINANCIAL OFFICER OF

AMEREN ILLINOIS COMPANY

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

In connection with the report on Form 10-Q for the quarterly period ended March 31, 2017 of Ameren Illinois Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the "Form 10-Q"), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 5, 2017

 /s/ Richard J. Mark

Richard J. Mark

Chairman and President

(Principal Executive Officer)

 /s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	Apr. 28, 2017
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Trading Symbol	AEE
Entity Registrant Name	AMEREN CORP
Entity Central Index Key	0001002910
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		242,634,798
Union Electric Company
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Entity Registrant Name	UNION ELECTRIC CO
Entity Central Index Key	0000100826
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		102,123,834
Ameren Illinois Company
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Entity Registrant Name	AMEREN ILLINOIS CO
Entity Central Index Key	0000018654
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		25,452,373

XML

Consolidated Statement of Income (Loss) - USD ($) shares in Millions, $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Operating Revenues:
Electric		$ 1,206	$ 1,102
Gas		308	332
Total operating revenues		1,514	1,434
Operating Expenses:
Fuel		206	203
Purchased power		180	138
Gas purchased for resale		130	152
Other operations and maintenance		405	400
Depreciation and amortization		221	207
Taxes other than income taxes		118	114
Total operating expenses		1,260	1,214
Operating Income		254	220
Other Income and Expenses:
Miscellaneous income	[1]	15	20
Miscellaneous expense	[1]	9	7
Total other income (expense)		6	13
Interest Charges		99	95
Income Before Income Taxes		161	138
Income Taxes		57	31
Net income		104	107
Pension and other postretirement benefit plan activity, net of income taxes (benefit)		0	(2)
Comprehensive Income		102	103
Less: Net Income Attributable to Noncontrolling Interests		2	2
Net Income Attributable to Ameren Common Shareholders		$ 102	$ 105
Earnings Per Share, Basic and Diluted [Abstract]
Earnings Per Share, Basic and Diluted		$ 0.42	$ 0.43
Dividends per Common Share		$ 0.44	$ 0.425
Average Common Shares Outstanding - Basic		242.6	242.6
Union Electric Company
Operating Revenues:
Electric		$ 746	$ 694
Gas		44	47
Total operating revenues		790	741
Operating Expenses:
Fuel		206	203
Purchased power		91	42
Gas purchased for resale		20	21
Other operations and maintenance		212	212
Depreciation and amortization		133	127
Taxes other than income taxes		75	73
Total operating expenses		737	678
Operating Income		53	63
Other Income and Expenses:
Miscellaneous income		12	15
Miscellaneous expense		2	2
Total other income (expense)		10	13
Interest Charges		54	52
Income Before Income Taxes		9	24
Income Taxes		3	9
Net income		6	15
Other Comprehensive Income		0	0
Comprehensive Income		6	15
Earnings Per Share, Basic and Diluted [Abstract]
Preferred Stock Dividends		1	1
Net Income Available to Common Stockholder		5	14
Ameren Illinois Company
Operating Revenues:
Electric		439	392
Gas		264	285
Total operating revenues		703	677
Operating Expenses:
Purchased power		101	104
Gas purchased for resale		110	131
Other operations and maintenance		197	194
Depreciation and amortization		83	77
Taxes other than income taxes		40	38
Total operating expenses		531	544
Operating Income		172	133
Other Income and Expenses:
Miscellaneous income		3	5
Miscellaneous expense		6	5
Total other income (expense)		(3)	0
Interest Charges		37	35
Income Before Income Taxes		132	98
Income Taxes		52	38
Net income		80	60
Pension and other postretirement benefit plan activity, net of income taxes (benefit)		0	(1)
Comprehensive Income		80	59
Earnings Per Share, Basic and Diluted [Abstract]
Preferred Stock Dividends		1	1
Net Income Available to Common Stockholder		$ 79	$ 59

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

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Consolidated Statement of Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Pension and other postretirement benefit plan activity, tax expense (benefit)	$ 0	$ 1
Ameren Illinois Company
Pension and other postretirement benefit plan activity, tax expense (benefit)	$ 0	$ (1)

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Consolidated Statement of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 104	$ 107
Other Comprehensive Loss, Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes (benefit)	0	(2)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	104	105
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	2	2
Comprehensive Income Attributable to Ameren Common Shareholders	$ 102	$ 103

XML

Consolidated Statement of Comprehensive Income (Loss) Consolidated Statement of Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Pension and other postretirement benefit plan activity, tax expense (benefit)	$ 0	$ 1

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Consolidated Balance Sheet - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 8	$ 9
Accounts receivable - trade (less allowance for doubtful accounts)	457	437
Unbilled revenue	228	295
Miscellaneous accounts and notes receivable	67	63
Materials and supplies	467	527
Current regulatory assets	118	149
Other current assets	105	113
Total current assets	1,450	1,593
Property and Plant, Net	20,298	20,113
Investments and Other Assets:
Nuclear decommissioning trust fund	635	607
Goodwill	411	411
Regulatory assets	1,485	1,437
Other assets	532	538
Total investments and other assets	3,063	2,993
TOTAL ASSETS	24,811	24,699
Current Liabilities:
Current maturities of long-term debt	681	681
Short-term Debt	914	558
Accounts and wages payable	460	805
Taxes accrued	77	46
Interest accrued	100	93
Customer deposits	106	107
Current regulatory liabilities	144	110
Other current liabilities	280	274
Total current liabilities	2,762	2,674
Long-term Debt, Net	6,597	6,595
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	4,321	4,264
Accumulated deferred investment tax credits	53	55
Regulatory liabilities	1,982	1,985
Asset retirement obligations	641	635
Pension and other postretirement benefits	768	769
Other deferred credits and liabilities	481	477
Total deferred credits and other liabilities	8,246	8,185
Commitments and Contingencies
Stockholders' Equity:
Common Stock	2	2
Other paid-in capital	5,522	5,556
Retained earnings	1,563	1,568
Accumulated other comprehensive income (loss)	(23)	(23)
Stockholder's equity	7,064	7,103
Noncontrolling Interest	142	142
Total equity	7,206	7,245
TOTAL LIABILITIES AND EQUITY	24,811	24,699
Union Electric Company
Current Assets:
Cash and cash equivalents	0	0
Advances to money pool	0	161
Accounts receivable - trade (less allowance for doubtful accounts)	175	187
Accounts receivable - affiliates	15	12
Unbilled revenue	126	154
Miscellaneous accounts and notes receivable	23	14
Materials and supplies	381	392
Current regulatory assets	23	35
Other current assets	45	49
Total current assets	788	1,004
Property and Plant, Net	11,471	11,478
Investments and Other Assets:
Nuclear decommissioning trust fund	635	607
Regulatory assets	606	619
Other assets	314	327
Total investments and other assets	1,555	1,553
TOTAL ASSETS	13,814	14,035
Current Liabilities:
Current maturities of long-term debt	431	431
Short-term Debt	36	0
Accounts and wages payable	191	444
Accounts payable - affiliates	54	68
Taxes accrued	63	30
Interest accrued	53	54
Current regulatory liabilities	8	12
Other current liabilities	128	123
Total current liabilities	964	1,162
Long-term Debt, Net	3,564	3,563
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	3,017	3,013
Accumulated deferred investment tax credits	51	53
Regulatory liabilities	1,240	1,215
Asset retirement obligations	635	629
Pension and other postretirement benefits	292	291
Other deferred credits and liabilities	16	19
Total deferred credits and other liabilities	5,251	5,220
Commitments and Contingencies
Stockholders' Equity:
Common Stock	511	511
Other paid-in capital	1,828	1,828
Preferred stock	80	80
Retained earnings	1,616	1,671
Stockholder's equity	4,035	4,090
TOTAL LIABILITIES AND EQUITY	13,814	14,035
Ameren Illinois Company
Current Assets:
Cash and cash equivalents	0	0
Accounts receivable - trade (less allowance for doubtful accounts)	270	242
Accounts receivable - affiliates	10	10
Unbilled revenue	102	141
Miscellaneous accounts and notes receivable	17	22
Materials and supplies	86	135
Current regulatory assets	91	108
Other current assets	16	25
Total current assets	592	683
Property and Plant, Net	7,596	7,469
Investments and Other Assets:
Goodwill	411	411
Regulatory assets	875	816
Other assets	95	95
Total investments and other assets	1,381	1,322
TOTAL ASSETS	9,569	9,474
Current Liabilities:
Current maturities of long-term debt	250	250
Short-term Debt	68	51
Accounts and wages payable	198	264
Accounts payable - affiliates	57	63
Taxes accrued	13	16
Interest accrued	42	33
Customer deposits	68	69
Mark-to-market derivative liabilities	18	15
Current environmental remediation	42	38
Current regulatory liabilities	118	78
Other current liabilities	88	94
Total current liabilities	962	971
Long-term Debt, Net	2,338	2,338
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,682	1,631
Accumulated deferred investment tax credits	2	2
Regulatory liabilities	739	768
Pension and other postretirement benefits	345	346
Environmental remediation	152	162
Other deferred credits and liabilities	236	222
Total deferred credits and other liabilities	3,156	3,131
Commitments and Contingencies
Stockholders' Equity:
Common Stock	0	0
Other paid-in capital	2,005	2,005
Preferred stock	62	62
Retained earnings	1,046	967
Stockholder's equity	3,113	3,034
TOTAL LIABILITIES AND EQUITY	$ 9,569	$ 9,474

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Consolidated Balance Sheet (Parenthetical) - USD ($) shares in Millions, $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Accounts receivable - trade allowance for doubtful accounts	$ 19	$ 19
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	400.0	400.0
Common stock, shares outstanding	242.6	242.6
Union Electric Company
Accounts receivable - trade allowance for doubtful accounts	$ 6	$ 7
Common stock, par value	$ 5	$ 5
Common stock, shares authorized	150.0	150.0
Common stock, shares outstanding	102.1	102.1
Ameren Illinois Company
Accounts receivable - trade allowance for doubtful accounts	$ 13	$ 12
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	45.0	45.0
Common stock, shares outstanding	25.5	25.5

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Consolidated Statement of Cash Flows - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Cash Flows From Operating Activities:
Net income		$ 104	$ 107
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		217	210
Amortization of nuclear fuel		24	24
Amortization of debt issuance costs and premium/discounts		6	6
Deferred income taxes and investment tax credits, net		51	42
Allowance for equity funds used during construction	[1]	(6)	(8)
Share-based compensation costs		4	6
Other		(4)	(3)
Changes in assets and liabilities:
Receivables		44	55
Inventories		60	55
Accounts and wages payable		(231)	(246)
Taxes accrued		36	30
Regulatory assets and liabilities		7	81
Assets, other		7	7
Liabilities, other		3	(26)
Pension and other postretirement benefits		9	9
Net cash provided by operating activities		331	349
Cash Flows From Investing Activities:
Capital expenditures		(504)	(496)
Nuclear fuel expenditures		(27)	(21)
Purchases of securities - nuclear decommissioning trust fund		(64)	(130)
Sales and maturities of securities - nuclear decommissioning trust fund		58	125
Other		(2)	12
Net cash used in investing activities		(539)	(510)
Cash Flows From Financing Activities:
Dividends on common stock		(107)	(103)
Dividends paid to noncontrolling interest holders		(2)	(2)
Short-term debt, net		356	280
Maturities of Long-term Debt		0	(260)
Share-based payments		(39)	(32)
Other		(1)	(1)
Net cash provided by (used in) financing activities		207	(118)
Net change in cash and cash equivalents		(1)	(279)
Cash and cash equivalents at beginning of period		9	292
Cash and cash equivalents at end of period		8	13
Union Electric Company
Cash Flows From Operating Activities:
Net income		6	15
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		127	130
Amortization of nuclear fuel		24	24
Amortization of debt issuance costs and premium/discounts		2	2
Deferred income taxes and investment tax credits, net		2	9
Allowance for equity funds used during construction		(5)	(7)
Other		1	0
Changes in assets and liabilities:
Receivables		28	81
Inventories		11	(2)
Accounts and wages payable		(186)	(172)
Taxes accrued		35	31
Regulatory assets and liabilities		29	45
Assets, other		11	5
Liabilities, other		4	3
Pension and other postretirement benefits		4	5
Net cash provided by operating activities		93	169
Cash Flows From Investing Activities:
Capital expenditures		(196)	(178)
Nuclear fuel expenditures		(27)	(21)
Purchases of securities - nuclear decommissioning trust fund		(64)	(130)
Sales and maturities of securities - nuclear decommissioning trust fund		58	125
Money pool advances, net		161	36
Other		0	(2)
Net cash used in investing activities		(68)	(170)
Cash Flows From Financing Activities:
Dividends on common stock		(60)	(140)
Dividends on preferred stock		(1)	(1)
Short-term debt, net		36	165
Maturities of Long-term Debt		0	(260)
Capital contribution from parent		0	38
Net cash provided by (used in) financing activities		(25)	(198)
Net change in cash and cash equivalents		0	(199)
Cash and cash equivalents at beginning of period		0	199
Cash and cash equivalents at end of period		0	0
Ameren Illinois Company
Cash Flows From Operating Activities:
Net income		80	60
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		83	77
Amortization of debt issuance costs and premium/discounts		3	4
Deferred income taxes and investment tax credits, net		51	37
Allowance for equity funds used during construction		(1)	(1)
Other		0	(3)
Changes in assets and liabilities:
Receivables		16	(22)
Inventories		49	57
Accounts and wages payable		(51)	(33)
Taxes accrued		(2)	(3)
Regulatory assets and liabilities		(19)	32
Assets, other		2	7
Liabilities, other		(5)	12
Pension and other postretirement benefits		5	4
Net cash provided by operating activities		212	229
Cash Flows From Investing Activities:
Capital expenditures		(227)	(211)
Money pool advances, net		0	(58)
Net cash used in investing activities		(227)	(269)
Cash Flows From Financing Activities:
Dividends on common stock		0	(30)
Dividends on preferred stock		(1)	(1)
Short-term debt, net		17	0
Other		(1)	0
Net cash provided by (used in) financing activities		15	(31)
Net change in cash and cash equivalents		0	(71)
Cash and cash equivalents at beginning of period		0	71
Cash and cash equivalents at end of period		$ 0	$ 0

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

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Summary Of Significant Accounting Policies

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005. Ameren’s primary assets are its equity interests in its subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. 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. Ameren also has various other subsidiaries that conduct other activities, such as the provision of shared services. Ameren is also evaluating competitive electric transmission investment opportunities outside of MISO as they arise.

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

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

• ATXI 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’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. All tabular dollar amounts are in millions, unless otherwise indicated. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.

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. See Note 2 – Rate and Regulatory Matters for information regarding the 2017 change in Ameren Illinois' method used to recognize interim period revenue in connection with the revenue decoupling provisions of the FEJA. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

Discontinued operations were immaterial to all periods presented in Ameren’s financial statements. As such, the December 31, 2016 balance sheet presentation of discontinued operations has been reclassified in this report to “Other current assets” for assets of discontinued operations and to “Other current liabilities” for liabilities of discontinued operations. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K for additional information.

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri, and Ameren Illinois increased during the three months ended March 31, 2017, to reflect the accretion of the estimated obligation due to the passage of time, partially offset by immaterial settlements.

Share-based Compensation

A summary of nonvested performance share units at March 31, 2017, and changes during the three months ended March 31, 2017, under the 2014 Incentive Plan are presented below:

	Performance Share Units
	Share Units		Weighted-average Fair Value per Share Unit
Nonvested at January 1, 2017	1,059,639		$	48.04
Granted(a)	496,068		59.16
Forfeitures	(3,192	)	49.13
Vested(b)	(3,779	)	52.88
Nonvested at March 31, 2017	1,548,736		$	51.59

(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 vary depending on actual performance over the three-year measurement period.

The fair value of each performance share unit awarded in 2017 under the 2014 Incentive Plan was determined to be $59.16, which was based on Ameren’s closing common share price of $52.46 at December 31, 2016, 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 beginning January 1, 2017 relative to the designated peer group. 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 1.47%, volatility of 15% to 21% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.

Operating Revenue

The Ameren Companies record operating revenue for electric or natural gas service when it is delivered to customers. We accrue an estimate of electric and natural gas revenues for service rendered but unbilled at the end of each accounting period. For certain regulatory recovery mechanisms qualifying as alternative revenue programs, such as revenue requirement reconciliations, the Ameren Companies recognize revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected from customers within two years.

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 therefore are 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 months ended March 31, 2017 and 2016:

	Three Months
	2017		2016
Ameren Missouri	$	31	$	30
Ameren Illinois	19		20
Ameren	$	50	$	50

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three months ended March 31, 2017 and 2016. The assumed settlement of dilutive performance share units had an immaterial impact on earnings per share. There were no potentially dilutive securities excluded from the earnings per diluted share calculations for the three months ended March 31, 2017 and 2016.

Accounting and Reporting Developments

Below is a summary of updates related to our adoption of recently issued authoritative accounting standards. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K for additional information about recently issued authoritative accounting standards relating to leases, financial instruments, restricted cash, and the consolidation analysis for variable interest entities and voting interest entities.

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative 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 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, as well as separate presentation of alternative revenue programs. Entities can apply the guidance to each reporting period presented, the full retrospective method, or by recording a cumulative effect adjustment to retained earnings in the period of initial adoption, the modified retrospective method.

During the first quarter of 2017, we determined that contributions in aid of construction and similar arrangements are not within the scope of this guidance. Therefore, our accounting for such arrangements will not change upon adoption of this guidance. In addition, we determined that the calculation of revenue and bad debt expense for tariff sales contracts will not materially change as a result of the collectibility criterion included within the guidance. We plan to complete our assessment of the impacts of this guidance on our results of operations, financial position, disclosures, and determine our transition method, in the next few months prior to our adoption in the first quarter of 2018.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In February 2017, the FASB issued authoritative guidance that requires an entity to retrospectively report the service cost component of net benefit cost in the same line item(s) as other compensation costs arising from services rendered by employees during the periodand to present the other components of net benefit cost in the income statement separately from the service cost component, and outside of operating income. The guidance also requires that an entity only capitalize the service cost component as part of an asset such as inventory or property, plant, and equipment on a prospective basis. Previously, all of the net benefit cost components were eligible for capitalization. The adoption of this guidance in the first quarter of 2018 may result in the recognition of new regulatory assets related to the recovery of, and return on, the non-service cost components of net benefit cost and related allowance for funds used during construction balances. We are currently assessing the impacts of this guidance on our results of operations, financial position, and disclosures.

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Rate And Regulatory Matters

3 Months Ended

Mar. 31, 2017

Public Utilities, General Disclosures [Abstract]

RATE AND REGULATORY MATTERS

RATE AND REGULATORY MATTERS

Below is a summary of updates to significant regulatory proceedings and related lawsuits. See also Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.

Missouri

March 2017 Electric Rate Order

In March 2017, the MoPSC issued an order approving a unanimous stipulation and agreement in Ameren Missouri’s July 2016 regulatory rate review. The order resulted in a $3.4 billion revenue requirement, which is a $92 million increase in Ameren Missouri’s annual revenue requirement for electric service, compared to its prior revenue requirement established in the MoPSC's April 2015 electric rate order. The new rates, base level of expenses, and amortizations became effective on April 1, 2017.

The order included the continued use of the FAC and the regulatory tracking mechanisms for pension and postretirement benefits, uncertain income tax positions, and renewable energy standards that the MoPSC authorized in earlier electric rate orders. These regulatory tracking mechanisms provide for a base level of expense to be reflected in Ameren Missouri’s base electric rates with differences in the actual expenses incurred recorded as a regulatory asset or liability. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs decrease by$54 millionfrom the base level established in the MoPSC's April 2015 electric rate order. Changes in amortizations and the base level of expenses for the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, reduced expenses by$26 millionfrom the base levels established in the MoPSC's April 2015 electric rate order.

ATXI’s Mark Twain Project

The Mark Twain project is a MISO-approved 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 conditioned upon ATXI obtaining county assents for road crossings. None of the five county commissions have approved ATXI’s requests for the assents. In October 2016, ATXI filed suit in the circuit courts for each of the five counties to obtain the assents for the original project route. A decision in each of the five lawsuits is expected in late 2017. In March 2017, the MoPSC’s April 2016 order was vacated by the Missouri Court of Appeals, Western District, which ruled that the MoPSC could not lawfully grant a certificate of convenience and necessity conditioned upon ATXI obtaining the assents. ATXI is evaluating whether to appeal the March 2017 Court of Appeals decision to the Missouri Supreme Court.

In April 2017, ATXI reached agreements in principle with a cooperative electric company in northeast Missouri and with Ameren Missouri to locate portions of the Mark Twain project on existing transmission line corridors, resulting in a proposed alternative project route. ATXI will finalize the proposed alternative project route and then request assents for road crossings from the five affected counties. If all five county commissions provide assents for the proposed alternative project route, ATXI will then seek MoPSC approval.

ATXI plans to complete the project in 2019; however, delays in obtaining the assents and approval from the MoPSC could delay completion.

Illinois

IEIMA & FEJA

Under the provisions of Illinois law, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs and allowed return on equity. This revenue requirement reconciliation qualifies as an alternative revenue program under GAAP. 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 and investment return. As of March 31, 2017, Ameren Illinois had recorded regulatory assets of $24 million and $54 million to reflect its 2016 revenue requirement reconciliation adjustment, which was included in the April 2017 formula rate update discussed below, and the approved 2015 revenue requirement reconciliation adjustment, with interest, respectively. For the three months ended March 31, 2017, Ameren Illinois recorded a regulatory asset of $46 million to reflect the difference between Ameren Illinois’ estimate of its revenue requirement and the revenue requirement reflected in customer rates.

In April 2017, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for 2018 rates. Pending ICC approval, this update filing will result in a$16 milliondecrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2018.This update reflects an increase to the annual formula rate based on 2016 actual costs and expected net plant additions for 2017, an increase to include the 2016 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the 2015 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2017, consistent with the ICC’s December 2016 annual update filing order. The revenue requirement decrease in the April 2017 update filing is a result of the 2015 revenue requirement reconciliation adjustment being larger than the 2016 revenue requirement reconciliation adjustment.An ICC decision regarding the revenue requirement to be used for customer rates in 2018 is expected by December 2017.

The FEJA revised certain portions of the IEIMA, including extending the IEIMA formula ratemaking process through 2022, and clarifying that a common equity ratio of up to, and including, 50% is prudent. Beginning in 2017, the FEJA provides that Ameren Illinois will recover, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes. Prior to the FEJA, Ameren Illinois’ interim period revenue recognition was volume-based, as revenues were affected by the timing of sales volumes due to seasonal rates and changes in volumes resulting from, among other things, weather and energy efficiency. This previous revenue recognition method resulted in more revenues during the third quarter, and less revenues during the other quarters of each year. Beginning in 2017, in connection with the decoupling provisions of the FEJA, Ameren Illinois changed its method used to recognize interim period revenue. Ameren Illinois will now recognize revenue consistent with the timing of actual incurred electric distribution recoverable costs and recognize revenue associated with the expected return on its rate base ratably over the year. Ameren Illinois recognized $46 million and $11 million of electric distribution revenue to reflect the difference between the estimate of its revenue requirement and the revenue requirement reflected in customer rates for the three months ended March 31, 2017 and March 31, 2016, respectively.

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 FERC-regulated transmission rate base under the MISO tariff from 12.38% to 9.15%. In September 2016, the FERC issued a final order in the November 2013 complaint case, which lowered the allowed base return on common equity for the 15-month period of November 2013 to February 2015 to 10.32%, or a 10.82% total allowed return on common equity with the inclusion of the 50 basis point incentive adder for participation in an RTO. The order required customer refunds, with interest, to be issued for that 15-month period. During the first quarter of 2017, Ameren and Ameren Illinois refunded $21 million and $17 million, respectively, related to the November 2013 complaint case. In addition, the 10.82% allowed return on common equity has been reflected in rates since September 2016.

As 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 further reduction in the allowed base return on common equity for the FERC-regulated transmission rate base under the MISO tariff. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case, which if approved by the FERC, would lower the allowed base return on common equity for the 15-month period of February 2015 to May 2016 to 9.70%, or a 10.20% total allowed return on equity with the inclusion of the 50 basis point incentive adder for participation in an RTO and require customer refunds, with interest, for that 15-month period. The timing of the issuance of the final order in the February 2015 complaint case, which will prospectively replace the current 10.82% allowed return on equity, is uncertain for two reasons. First, at this time the FERC lacks a quorum of three commissioners. Second, the United States Court of Appeals for the District of Columbia recently vacated and remanded to the FERC an order in a separate case in which the FERC established the allowed base return on common equity methodology used in the two MISO complaint cases described above. Ameren is unable to predict the impact of the outcome of the United States Court of Appeals for the District of Columbia Circuit’s remand on the MISO FERC complaint cases at this time. 

As of March 31, 2017, Ameren and Ameren Illinois recorded current regulatory liabilities of $41 million and $24 million, respectively, to reflect the expected refunds, including interest, associated with the reduced allowed returns on common equity in the initial decision in the February 2015 complaint case. Ameren Missouri does not expect that a reduction in the FERC-allowed base return on common equity would be material to its results of operations, financial position, or liquidity.

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Short-Term Debt And Liquidity

3 Months Ended

Mar. 31, 2017

Line of Credit Facility [Abstract]

SHORT-TERM DEBT AND LIQUIDITY

SHORT-TERM DEBT AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash, drawings under committed credit agreements, commercial paper issuances, or, in the case of Ameren Missouri and Ameren Illinois, short-term intercompany borrowings. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, in the Form 10-K for a description of our indebtedness provisions and other covenants as well as a description of money pool arrangements.

The Missouri Credit Agreement and the Illinois Credit Agreement, both of which expire in December 2021, were not utilized for direct borrowings during the three months ended March 31, 2017, 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, the aggregate amount of credit capacity available under the Credit Agreements to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, at March 31, 2017, was $1.2 billion. The Ameren Companies were in compliance with the covenants in their credit agreements as of March 31, 2017. As of March 31, 2017, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the provisions of the Credit Agreements, were 53%, 48%, and 46% for Ameren, Ameren Missouri, and Ameren Illinois, respectively.

Commercial Paper

The following table presents commercial paper outstanding as of March 31, 2017, and December 31, 2016:

	2017		2016
Ameren (parent)	$	810	$	507
Ameren Missouri	36		—
Ameren Illinois	68		51
Ameren Consolidated	$	914	$	558

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 three months ended March 31, 2017 and 2016:

	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated
2017
Average daily commercial paper outstanding	$	682		$	4		$	50		$	736
Weighted-average interest rate	1.07		%	0.93		%	0.95		%	1.06		%
Peak commercial paper during period(a)	$	810		$	45		$	74		$	914
Peak interest rate	1.30		%	1.15		%	1.15		%	1.30		%
2016
Average daily commercial paper outstanding	$	349		$	68		$	—		$	417
Weighted-average interest rate	0.82		%	0.80		%	—		%	0.81		%
Peak commercial paper during period(a)	$	482		$	208		$	—		$	581
Peak interest rate	0.95		%	0.85		%	—		%	0.95		%

(a) The timing of peak commercial paper issuances varies by company. Therefore, the sum of peak commercial paper issuances presented by company does not equal the Ameren Consolidated peak commercial paper issuances for the period.

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.

The average interest rate for borrowing under the utility money pool for the three months ended March 31, 2017 and 2016, was 1.01% and 0.47%, respectively.

See Note 8 – Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three months ended March 31, 2017 and 2016.

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Long-Term Debt And Equity Financings

3 Months Ended

Mar. 31, 2017

Long-Term Debt And Equity Financings [Abstract]

LONG-TERM DEBT AND EQUITY FINANCINGS

LONG-TERM DEBT AND EQUITY FINANCINGS

Indenture Provisions and Other Covenants

Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions, but would restrict the companies’ ability to issue first mortgage bonds or preferred stock. See Note 5 – Long-Term Debt and Equity Financings under Part II, Item 8, in the Form 10-K for a description of our indenture provisions and other covenants as well as restrictions on the payment of dividends. The Ameren Companies were in compliance with those indenture provisions and other covenants as of March 31, 2017.

Off-Balance-Sheet Arrangements

At March 31, 2017, 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.

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Other Income and Expenses

3 Months Ended

Mar. 31, 2017

Other Nonoperating Income (Expense) [Abstract]

OTHER INCOME AND EXPENSES

OTHER INCOME AND EXPENSES

The following table presents the components of “Other Income and Expenses” in the Ameren Companies’ statements of income for the three months ended March 31, 2017 and 2016:

	Three Months
	2017	2016
Ameren:(a)
Miscellaneous income:

	Three Months
	2017		2016
Allowance for equity funds used during construction	$	6	$	8
Interest income on industrial development revenue bonds	7		7
Interest income	2		4
Other	—		1
Total miscellaneous income	$	15	$	20
Miscellaneous expense:
Donations	$	5	$	5
Other	4		2
Total miscellaneous expense	$	9	$	7
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	5	$	7
Interest income on industrial development revenue bonds	7		7
Other	—		1
Total miscellaneous income	$	12	$	15
Miscellaneous expense:
Donations	$	—	$	1
Other	2		1
Total miscellaneous expense	$	2	$	2
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	1	$	1
Interest income	2		4
Total miscellaneous income	$	3	$	5
Miscellaneous expense:
Donations	$	4	$	4
Other	2		1
Total miscellaneous expense	$	6	$	5

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

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Derivative Financial Instruments

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE FINANCIAL INSTRUMENTS

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 March 31, 2017 and December 31, 2016. As of March 31, 2017, these contracts extended through October 2019, March 2023, May 2032, and February 2020 for fuel oils, natural gas, power, and uranium, respectively.

	Quantity (in millions, except as indicated)
	2017			2016
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)(a)	36	(b)	36	30	(b)	30
Natural gas (in mmbtu)	28	149	177	25	129	154
Power (in megawatthours)	1	9	10	1	9	10
Uranium (pounds in thousands)	345	(b)	345	345	(b)	345

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

(b) Not applicable.

All contracts considered to be derivative instruments are required to 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 March 31, 2017 and December 31, 2016, all contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral.

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 March 31, 2017 and December 31, 2016:

	Balance Sheet Location	Ameren Missouri			Ameren Illinois		Ameren
2017
Fuel oils	Other current assets	$	1		$	—	$	1
	Other assets	1			—		1
Natural gas	Other current assets	—			5		5
Power	Other current assets	5			—		5
	Total assets (a)	$	7		$	5	$	12
Fuel oils	Other current liabilities	$	5		$	—	$	5
Natural gas	MTM derivative liabilities	(b)			6		(b)
	Other current liabilities	2			—		8
	Other deferred credits and liabilities	6			9		15
Power	MTM derivative liabilities	(b)			12		(b)
	Other current liabilities	1			—		13
	Other deferred credits and liabilities	—			182		182
Uranium	Other deferred credits and liabilities	—		(c)	—		—		(c)
	Total liabilities (d)	$	14		$	209	$	223
2016
Fuel oils	Other current assets	$	2		$	—	$	2
	Other assets	1			—		1
Natural gas	Other current assets	1			11		12
	Other assets	1			2		3
Power	Other current assets	9			—		9
	Total assets (a)	$	14		$	13	$	27
Fuel oils	Other current liabilities	$	5		$	—	$	5
Natural gas	MTM derivative liabilities	(b)			3		(b)
	Other current liabilities	1			—		4
	Other deferred credits and liabilities	5			5		10
Power	MTM derivative liabilities	(b)			12		(b)
	Other current liabilities	3			—		15
	Other deferred credits and liabilities	—			173		173
Uranium	Other deferred credits and liabilities	4			—		4
	Total liabilities (d)	$	18		$	193	$	211

(a) 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) Beginning in 2017, as a result of rulebook amendments at the Chicago Mercantile Exchange, the fair value of uranium derivative liabilities are offset by certain settlement payments made to the exchange previously characterized as collateral and included within “Other assets” on Ameren’s and Ameren Missouri’s balance sheet.

(d) 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; these contracts 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 Ameren Companies elect to present the fair value amounts of derivative assets and derivative liabilities subject to an enforceable master netting arrangement or similar agreement gross on the balance sheet. However, if the gross amounts recognized on the balance sheet were netted with derivative instruments and cash collateral received or posted, the net amounts would not be materially different from the gross amounts at March 31, 2017 and December 31, 2016.

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. As of March 31, 2017, 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 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 March 31, 2017, 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 March 31, 2017, 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)
2017
Ameren Missouri	$	58	$	8	$	44
Ameren Illinois	38		—		30
Ameren	$	96	$	8	$	74

(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.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

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 March 31, 2017 and December 31, 2016:

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
Level 3 Derivative asset and liability – commodity contracts(a):
2017
	Fuel oils	$	1	$	(1	)	Option model	Volatilities(%)(b)	23 – 35	27
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.12 – 0.22	0.15

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
								Ameren Missouri credit risk(%)(c)(d)	0.37	(e)
								Escalation rate (%)(b)(f)	0 – 1	0
	Natural gas	—		(2		)	Discounted cash flow	Nodal basis ($/mmbtu)(b)	(0.80) – (0.10)	(0.70)
								Counterparty credit risk (%)(c)(d)	0.45 – 6	0.70
								Ameren Illinois credit risk (%)(c)(d)	0.37	(e)
	Power(g)	5		(195		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)(h)	25 – 44	29
								Estimated auction price for FTRs ($/MW)(b)	(89) – 1,568	164
								Nodal basis ($/MWh)(h)	(4) – 0	(2)
								Ameren Illinois credit risk (%)(c)(d)	0.37	(e)
							Fundamental energy production model	Estimated future gas prices ($/mmbtu)(b)	3 – 4	3
								Escalation rate (%)(b)(i)	3	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(b)	5 – 7	6
2016
	Fuel oils	$	1	$	—		Option model	Volatilities (%)(b)	24 – 66	28
							Discounted cash flow	Counterparty credit risk (%)(c)(d)	0.13 – 0.22	0.15
								Ameren Missouri credit risk (%)(c)(d)	0.38	(e)
								Escalation rate (%)(b)(f)	(2) – 2	0
	Natural gas	1		(1		)	Option model	Volatilities (%)(b)	31 – 66	36
								Nodal basis ($/mmbtu)(b)	(0.40) – (0.10)	(0.20)
							Discounted cash flow	Nodal basis ($/mmbtu)(b)	(0.80) – 0	(0.50)
								Counterparty credit risk (%)(c)(d)	0.13 – 8	1
								Ameren Illinois credit risk (%)(c)(d)	0.38	(e)
	Power(g)	9		(187		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)(h)	26 – 44	29
								Estimated auction price for FTRs ($/MW)(b)	(71) – 5,270	125
								Nodal basis ($/MWh)(h)	(6) – 0	(2)
								Ameren Illinois credit risk (%)(c)(d)	0.38	(e)
							Fundamental energy production model	Estimated future gas prices ($/mmbtu)(b)	3 – 4	3
								Escalation rate (%)(b)(i)	5	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(b)	5 – 7	6
	Uranium	—		(4		)	Option model	Volatilities (%)(b)	24	(e)
							Discounted cash flow	Average forward uranium pricing ($/pound)(b)	22 – 24	22
								Ameren Missouri credit risk (%)(c)(d)	0.38	(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) Escalation rate applies to fuel oil prices 2019 and beyond

(g) Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2021 for March 31, 2017 and through 2020 for December 31, 2016. Valuations beyond 2021 for March 31, 2017 and 2020 for December 31, 2016 use fundamentally modeled pricing by month for peak and off-peak demand.

(h) 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.

(i) Escalation rate applies to power prices in 2031 and beyond.

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 quarter of 2017 or 2016. At March 31, 2017 and December 31, 2016, 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 March 31, 2017:

		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable  Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
Ameren	Derivative assets – commodity contracts(a):
	Fuel oils	$	1	$	—	$	1	$	2
	Natural gas	1		4		—		5
	Power	—		—		5		5
	Total derivative assets – commodity contracts	$	2	$	4	$	6	$	12
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	420		—		—		420
	Debt securities:
	U.S. treasury and agency securities	—		118		—		118
	Corporate bonds	—		70		—		70
	Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	421	$	212	$	—	$	633	(b)
	Total Ameren	$	423	$	216	$	6	$	645
Ameren Missouri	Derivative assets – commodity contracts(a):
	Fuel oils	$	1	$	—	$	1	$	2
	Power	—		—		5		5
	Total derivative assets – commodity contracts	$	1	$	—	$	6	$	7
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	420		—		—		420
	Debt securities:
	U.S. treasury and agency securities	—		118		—		118
	Corporate bonds	—		70		—		70
	Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	421	$	212	$	—	$	633	(b)
	Total Ameren Missouri	$	422	$	212	$	6	$	640
Ameren Illinois	Derivative assets – commodity contracts(a):
	Natural gas	$	1	$	4	$	—	$	5
Liabilities:
Ameren	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	4	$	—	$	1	$	5
	Natural gas	—		21		2		23
	Power	—		—		195		195
	Total Ameren	$	4	$	21	$	198	$	223
Ameren Missouri	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	4	$	—	$	1	$	5
	Natural gas	—		8		—		8
	Power	—		—		1		1
	Total Ameren Missouri	$	4	$	8	$	2	$	14
Ameren Illinois	Derivative liabilities – commodity contracts(a):
	Natural gas	$	—	$	13	$	2	$	15
	Power	—		—		194		194
	Total Ameren Illinois	$	—	$	13	$	196	$	209

(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, 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
Assets:
Ameren	Derivative assets – commodity contracts(a):
	Fuel oils	$	2	$	—	$	1	$	3
	Natural gas	2		12		1		15
	Power	—		—		9		9
	Total derivative assets – commodity contracts	$	4	$	12	$	11	$	27
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	408		—		—		408
	Debt securities:
	U.S. treasury and agency securities	—		112		—		112
	Corporate bonds	—		67		—		67
	Other	—		17		—		17
	Total nuclear decommissioning trust fund	$	409	$	196	$	—	$	605	(b)
	Total Ameren	$	413	$	208	$	11	$	632
Ameren Missouri	Derivative assets – commodity contracts(a):
	Fuel oils	$	2	$	—	$	1	$	3
	Natural gas	—		1		1		2
	Power	—		—		9		9
	Total derivative assets – commodity contracts	$	2	$	1	$	11	$	14
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	408		—		—		408
	Debt securities:
	U.S. treasury and agency securities	—		112		—		112
	Corporate bonds	—		67		—		67
	Other	—		17		—		17
	Total nuclear decommissioning trust fund	$	409	$	196	$	—	$	605	(b)
	Total Ameren Missouri	$	411	$	197	$	11	$	619
Ameren Illinois	Derivative assets – commodity contracts(a):
	Natural gas	$	2	$	11	$	—	$	13
Liabilities:
Ameren	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	5	$	—	$	—	$	5
	Natural gas	—		13		1		14
	Power	—		1		187		188
	Uranium	—		—		4		4
	Total Ameren	$	5	$	14	$	192	$	211
Ameren Missouri	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	5	$	—	$	—	$	5
	Natural gas	—		6		—		6
	Power	—		1		2		3
	Uranium	—		—		4		4
	Total Ameren Missouri	$	5	$	7	$	6	$	18
Ameren Illinois	Derivative liabilities – commodity contracts(a):
	Natural gas	$	—	$	7	$	1	$	8
	Power	—		—		185		185
	Total Ameren Illinois	$	—	$	7	$	186	$	193

(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.

All costs related to financial assets and liabilities classified as Level 3 in the fair value hierarchy 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 months ended March 31, 2017 and 2016, 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.

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:

		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
For the three months ended March 31, 2017
Beginning balance at January 1, 2017	$	7		$	(185	)	$	(178	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			(10	)		(10	)
Settlements		(3	)		1			(2	)
Ending balance at March 31, 2017	$	4		$	(194	)	$	(190	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2017	$	—		$	(11	)	$	(11	)
For the three months ended March 31, 2016
Beginning balance at January 1, 2016	$	16		$	(170	)	$	(154	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(3	)		(21	)		(24	)
Settlements		(7	)		4			(3	)
Ending balance at March 31, 2016	$	6		$	(187	)	$	(181	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2016	$	—		$	(19	)	$	(19	)

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. For the three months ended March 31, 2017 and 2016, there were no material transfers between Level 1 and Level 2, Level 1 and Level 3, or 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 March 31, 2017 and December 31, 2016:

	March 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:
Long-term debt and capital lease obligations (including current portion)	$	7,278	$	7,762	$	7,276	$	7,772
Preferred stock(a)	142		129		142		131
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	3,995	$	4,312	$	3,994	$	4,304
Preferred stock	80		77		80		79
Ameren Illinois:
Long-term debt (including current portion)	$	2,588	$	2,742	$	2,588	$	2,765
Preferred stock	62		52		62		52

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

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Related Party Transactions

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

In the normal course of business, the Ameren Companies engage in affiliate transactions. These transactions primarily consist of power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our material related party agreements, see Note 14 – Related Party Transactions under Part II, Item 8, of the Form 10-K and the money pool arrangements discussed in Note 3 – Short-term Debt and Liquidity of this report.

Electric Power Supply Agreement

In April 2017, Ameren Illinois conducted a procurement event, administered by the IPA, to purchase energy products. Ameren Missouri was among the winning suppliers in this event. As a result, in April 2017, Ameren Missouri and Ameren Illinois entered into an energy product agreement by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, 85,600 megawatthours at an average price of $33.64 per megawatthour during the period of March 1, 2019, through May 31, 2020.

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three months ended March 31, 2017 and 2016:

				Three Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2017	$	11	$	(a)
agreements with Ameren Illinois		2016		9		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2017		7		1
rent and facility services		2016		6		1
Total Operating Revenues		2017	$	18	$	1
		2016		15		1
Ameren Illinois power supply	Purchased Power	2017	$	(a)	$	11
agreements with Ameren Missouri		2016		(a)		9
Ameren Illinois transmission	Purchased Power	2017		(a)		(b)
services with ATXI		2016		(a)		(b)
Total Purchased Power		2017	$	(a)	$	11
		2016		(a)		9
Ameren Services support services	Other Operations and Maintenance	2017	$	35	$	32
agreement		2016		34		31
Money pool borrowings (advances)	Interest Charges/ Miscellaneous Income	2017	$	(b)	$	(b)
		2016		(b)		(b)

(a) Not applicable.

(b) Amount less than $1 million.

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Commitments And Contingencies

3 Months Ended

Mar. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, authorities and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements in this report and in our Form 10-K, will not have a material adverse effect on our results of operations, financial position, or liquidity.

Reference is made to Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 14 – Related Party Transactions, and Note 15 – Commitments and Contingencies 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 of this report.

Other Obligations

In 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 March 31, 2017, 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 $3,824 million, $2,340 million, and $1,418 million, respectively. For additional information regarding our obligations and commitments at December 31, 2016, see Note 15 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

In April 2017, Ameren Illinois conducted a procurement event, administered by the IPA, to purchase energy products through May 31, 2020. In the April 2017 procurement event, Ameren Illinois contracted to purchase 4,249,800 megawatthours of energy products for $128 million from June 1, 2017, through May 31, 2020. See Note 8 – Related Party Transactions for additional information regarding energy product agreements between Ameren Missouri and Ameren Illinois as a result of this procurement event.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. The development and operation of electric generation, transmission, and distribution facilities and natural gas storage, transmission, and distribution facilities, can trigger compliance obligations with respect to diverse environmental laws and regulations. These laws and regulations address emissions, discharges to water, water usage, impacts to air, land, and water, and chemical and waste handling. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures.

The EPA has promulgated environmental regulations that 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. As of December 31, 2016, Ameren Missouri’s fossil-fueled energy centers represented 18% and 34% of Ameren’s and Ameren Missouri’s rate base, respectively. Recent regulations impacting air emissions from electric utility industry include revised NSPS, the CSAPR, the MATS and revised National Ambient Air Quality Standards, which are subject to periodic review for certain pollutants. Collectively, these regulations cover a variety of pollutants such as SO₂, particulate matter, NO_X, mercury, toxic metals and acid gases. Regulation of CO₂ emissions from existing power plants through the Clean Power Plan have been stayed by the United States Supreme Court. In addition, the EPA recently announced it is re-evaluating the legal and policy basis for the Clean Power Plan. Water intake and discharges from power plants are regulated under the Clean Water Act and could require significant capital expenditures, such as modifications to water intake structures at Ameren Missouri’s energy centers. The management and disposal of coal ash is regulated under the CCR Rule, which will require significant capital expenditures, such as the closure of surface impoundments and the installations of dry ash handling systems at several of our energy centers. The EPA has initiated an administrative review of several regulations and rulemaking activities, including the Clean Power Plan, the MATS, and the effluent limitation guidelines, which could ultimately result in the revision of all or part of such rules. However, the individual or combined effects of existing environmental regulations could result in significant capital expenditures and increased operating costs for Ameren and Ameren Missouri. Compliance with existing 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 further capital investment. Ameren and Ameren Missouri expect that such compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the timing of costs and their recovery could be subject to regulatory lag.

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 $425 million to $525 million in the aggregate from 2017 through 2021 in order to comply with existing environmental regulations. Ameren Missouri may be required to install additional environmental controls beyond 2021. This estimate of capital expenditures includes 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. 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 because of uncertainty as to whether the EPA will substantively revise regulatory obligations, 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 SO₂ and 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. The second phase of emission reduction requirements, which were revised by the EPA in 2016, became 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 did not make additional capital investments to comply with the 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

In 2015, the EPA issued 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. The Clean Power Plan sets forth CO₂ emissions standards applicable to existing power plants. The rule was stayed by the United States Supreme Court in February 2016, pending the outcome of various legal challenges. In April 2017, the EPA announced that it is reviewing and, if appropriate, will initiate proceedings to suspend, revise, or rescind the Clean Power Plan. The District of Columbia Circuit Court of Appeals has stayed further action on the litigation that resulted from the Supreme Court’s February 2016 stay of the Clean Power Plan pending the EPA’s administrative review.

The Clean Power Plan would require significant reductions in CO₂ emissions from power plants by 2030 including interim compliance periods commencing in 2022. The EPA has advised all states to discontinue implementation planning. We cannot predict the outcome of the EPA’s administrative review, nor the resulting impact on our results of operations, financial position, or liquidity.

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 complaint, as amended in October 2013, alleged 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. The litigation has been divided into two phases: liability and remedy. In January 2017, the district court issued a liability ruling that the projects violated provisions of the Clean Air Act and Missouri law. The case will now proceed to the second phase to determine the actions required to remedy the violations found in the liability phase of the litigation. The EPA previously withdrew all claims for penalties and fines. At the conclusion of both phases of the litigation, Ameren Missouri intends to appeal the liability ruling to the United States Circuit Court of Appeals for the Eighth Circuit. A decision by the district court regarding the remedy phase of the litigation could occur in 2019.

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. Among other things and subject to economic and regulatory considerations, resolution of this matter could result in increased capital expenditures for the installation of pollution control equipment, as well as increased operations and maintenance expenses. We are unable to predict the ultimate resolution of 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. All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to the cooling water intake structures rule. Implementation of the rule will occur during the permit renewal process of each energy center’s water discharge permit, which will occur between 2018 and 2023.

Additionally, in 2015, the EPA issued a rule to revise the effluent limitation guidelines applicable to steam electric generating units. These guidelines established national standards for water discharges that are based on the effectiveness of available control technology. The EPA's 2015 rule prohibits effluent discharges of certain waste streams and imposes more stringent limitations on certain water discharges from power plants. In April 2017, the EPA announced that it would review and reconsider the effluent limitation guidelines and administratively stayed all compliance deadlines.

Both the intake and effluent rules, if implemented as enacted, could have an adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity should such implementation require extensive modifications to the cooling water systems and water discharge systems at Ameren Missouri’s energy centers, and if such 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 from coal fired energy centers. These regulations affect CCR disposal and handling costs at Ameren Missouri's energy centers. They require closure of impoundments if performance criteria relating to groundwater impacts and location restrictions are not achieved. Ameren and Ameren Missouri’s AROs associated with CCR storage facilities reflect the regulations issued in 2015. Ameren plans to close these CCR storage facilities between 2018 and 2023.

Ameren Missouri's capital expenditure plan includes the cost of constructing landfills as part of its environmental compliance plan.

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 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 March 31, 2017, 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 2023. 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 March 31, 2017, Ameren Illinois estimated the obligation related to these former MGP sites at $193 million to $258 million. Ameren and Ameren Illinois recorded a liability of $193 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate.

The scope of the remediation activities at these former MGP sites 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 Missouri 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 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 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 remedies. As of March 31, 2017, 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.

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 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 March 31, 2017, and December 31, 2016, representing their estimate of the probable loss due as a result of this lawsuit. Ameren and Ameren Missouri believe there is a remote possibility that a liability relating to this lawsuit could be material to Ameren's 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. A 2018 trial has been set and an order is expected later that year.

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Callaway Energy Center

3 Months Ended

Mar. 31, 2017

Nuclear Waste Matters [Abstract]

CALLAWAY ENERGY CENTER

CALLAWAY ENERGY CENTER

Spent Nuclear Fuel

Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. The NWPA established the fee that Ameren Missouri and other utilities that own and operate those energy centers 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 was suspended in May 2014. 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 fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners sued the DOE to recover costs incurred for ongoing storage of their spent fuel. The lawsuit resulted in a settlement agreement that provides for annual reimbursement of additional spent fuel storage and related costs. For the three months ended March 31, 2017 and March 31, 2016, Ameren Missouri did not receive any such reimbursements. Ameren Missouri will continue to apply for reimbursement from the DOE for allowable costs associated with the ongoing storage of spent fuel.

Decommissioning

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 the annual decommissioning costs used to establish electric rates.

The fair value of the trust fund for Ameren Missouri's Callaway energy center is reported as "Nuclear decommissioning trust fund" in Ameren's and Ameren Missouri's balance sheets. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory liability. 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.

Supplier of Fuel Assemblies

The next scheduled refueling and maintenance outage at Ameren Missouri’s Callaway energy center will be in fall 2017. The Callaway energy center uses nuclear fuel assemblies fabricated by Westinghouse. Westinghouse is currently the only NRC-licensed supplier authorized to provide fuel assemblies to the Callaway energy center. During the first quarter of 2017, Westinghouse filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. Westinghouse could petition the bankruptcy court to reject Ameren Missouri’s contracts as part of the restructuring process, and if the bankruptcy court agrees, this could result in Ameren Missouri not having access to the fuel assemblies necessary to operate the Callaway energy center. At this time, Ameren and Ameren Missouri believe the restructuring proceeding will not affect Westinghouse’s performance under the terms of its existing contracts with Ameren Missouri, including with respect to the delivery of fuel assembles for the upcoming refueling and maintenance outage, and therefore do not expect any material impact to Ameren Missouri’s operations as a result of this restructuring proceeding. However, Ameren and Ameren Missouri could incur material unexpected costs as a result of the Westinghouse bankruptcy, such as the cost of replacement power, the loss of fuel inventory that is stored at Westinghouse’s facility, and payments made for fuel fabrication. A change of fuel suppliers or a change in the type of fuel assembly design that is currently licensed for use at the Callaway energy center could take an estimated three years of analysis and NRC licensing efforts to implement.

Insurance

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at March 31, 2017. The property coverage and the nuclear liability coverage renewal dates are April 1 and January 1, respectively, of each year. Both coverages were renewed in 2017.

Type and Source of Coverage	Maximum  Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	450		$	—
Pool participation	12,986		(a)	127		(b)
	$	13,436	(c)	$	127
Property damage:
NEIL and EMANI	$	3,200	(d)	$	29	(e)
Replacement power:
NEIL	$	490	(f)	$	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 $450 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. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.

(d) NEIL provides $2.7 billion in property damage, stabilization, decontamination, and premature decommissioning insurance for radiation events and $2.3 billion in property damage for nonradiation events. EMANI provides $490 million for both radiation and nonradiation events.

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

(f) 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 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 subject to industrywide aggregates, such that terrorist acts against one or more commercial nuclear power plants insured by NEIL or EMANI within a stated time period would be treated as a single event, and the owners of the nuclear power plants would share one full limit of liability. NEIL policies have an aggregate limit of $3.2 billion within a 12-month period for radiation events, or $1.8 billion for events not involving radiation contamination. The EMANI policies have an aggregate limit of €600 million for radiation and nonradiation events within a period of 72 hours.

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.

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Retirement Benefits

3 Months Ended

Mar. 31, 2017

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

RETIREMENT BENEFITS

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 months ended March 31, 2017 and 2016:

	Pension Benefits						Postretirement Benefits
	Three Months						Three Months
	2017			2016			2017			2016
Service cost	$	23		$	20		$	5		$	5
Interest cost	45			47			12			12
Expected return on plan assets	(66		)	(63		)	(19		)	(18		)
Amortization of:
Prior service benefit	—			—			(1		)	(1		)
Actuarial loss (gain)	14			9			(2		)	(3		)
Net periodic benefit cost (benefit)	$	16		$	13		$	(5	)	$	(5	)

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 months ended March 31, 2017 and 2016:

	Pension Benefits				Postretirement Benefits
	Three Months				Three Months
	2017		2016		2017			2016
Ameren Missouri(a)	$	6	$	8	$	(1	)	$	(1	)
Ameren Illinois	10		5		(4		)	(4		)
Ameren(a)(b)	$	16	$	13	$	(5	)	$	(5	)

(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.

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Segment Information

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. Ameren Illinois Natural Gas consists of the natural gas business of Ameren Illinois. Ameren Transmission is primarily composed of the aggregated electric transmission businesses of Ameren Illinois and ATXI, and associated Ameren (parent) interest charges. The category called Other primarily includes Ameren parent company activities and Ameren Services.

Ameren Missouri has one segment. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. See Note 1 – Summary of Significant Accounting Policies for additional information regarding the operations of Ameren Missouri and Ameren Illinois.

Segment operating revenues and a majority of operating expenses are directly recognized and incurred by Ameren Illinois to each Ameren Illinois segment. Common operating expenses, miscellaneous income and expenses, interest charges, and income tax expense are allocated by Ameren Illinois to each Ameren Illinois segment based on certain factors, which primarily relate to the nature of the cost. Additionally, Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. The transmission expense for Illinois customers who have elected to purchase their power from Ameren Illinois is recovered through a cost recovery mechanism with no net effect on Ameren Illinois Electric Distribution earnings, as costs are offset by corresponding revenues. Transmission revenues from these transactions are reflected at Ameren Transmission and Ameren Illinois Transmission. An intersegment elimination at Ameren and Ameren Illinois occurs to eliminate these transmission revenues and expenses.

The following tables present information about the reported revenues and specified items reflected in net income attributable to common shareholders and capital expenditures at Ameren and Ameren Illinois for the three months ended March 31,2017 and 2016. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.

Ameren

Three Months	Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission			Other				Intersegment Eliminations			Consolidated
2017
External revenues	$	772	$	384	$	264	$	96		$	(2	)		$	—		$	1,514
Intersegment revenues	18		1		—		6		(a)	—				(25		)	—
Net income attributable to Ameren common shareholders	5		30		33		34			—				—			102
Capital expenditures	196		120		51		134			4			(b)	(1		)	504
2016
External revenues	$	726	$	351	$	285	$	72		$	—			$	—		$	1,434
Intersegment revenues	15		1		—		11		(a)	—				(27		)	—
Net income attributable to Ameren common shareholders	14		11		35		27			18				—			105
Capital expenditures	178		117		35		164			2			(b)	—			496

(a) Ameren Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above.

(b) Includes the elimination of intercompany transfers.    

Ameren Illinois

	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission			Intersegment Eliminations			Consolidated
2017
External revenues	$	385	$	264	$	54		$	—		$	703
Intersegment revenues	—		—		6		(a)	(6		)	—
Net income available to common shareholder	30		33		16			—			79
Capital expenditures	120		51		56			—			227
2016
External revenues	$	352	$	285	$	40		$	—		$	677
Intersegment revenues	—		—		11		(a)	(11		)	—
Net income available to common shareholder	11		35		13			—			59
Capital expenditures	117		35		59			—			211

(a) Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above.

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Summary Of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Revenue Recognition, Policy [Policy Text Block]

The Ameren Companies record operating revenue for electric or natural gas service when it is delivered to customers. We accrue an estimate of electric and natural gas revenues for service rendered but unbilled at the end of each accounting period. For certain regulatory recovery mechanisms qualifying as alternative revenue programs, such as revenue requirement reconciliations, the Ameren Companies recognize revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected from customers within two years.

Consolidation

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. All tabular dollar amounts are in millions, unless otherwise indicated. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.

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. See Note 2 – Rate and Regulatory Matters for information regarding the 2017 change in Ameren Illinois' method used to recognize interim period revenue in connection with the revenue decoupling provisions of the FEJA. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

Excise Taxes

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 therefore are not included in Ameren Illinois’ revenues and expenses.

Accounting and Reporting Developments

is a summary of updates related to our adoption of recently issued authoritative accounting standards. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K for additional information about recently issued authoritative accounting standards relating to leases, financial instruments, restricted cash, and the consolidation analysis for variable interest entities and voting interest entities.

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative 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 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, as well as separate presentation of alternative revenue programs. Entities can apply the guidance to each reporting period presented, the full retrospective method, or by recording a cumulative effect adjustment to retained earnings in the period of initial adoption, the modified retrospective method.

During the first quarter of 2017, we determined that contributions in aid of construction and similar arrangements are not within the scope of this guidance. Therefore, our accounting for such arrangements will not change upon adoption of this guidance. In addition, we determined that the calculation of revenue and bad debt expense for tariff sales contracts will not materially change as a result of the collectibility criterion included within the guidance. We plan to complete our assessment of the impacts of this guidance on our results of operations, financial position, disclosures, and determine our transition method, in the next few months prior to our adoption in the first quarter of 2018.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In February 2017, the FASB issued authoritative guidance that requires an entity to retrospectively report the service cost component of net benefit cost in the same line item(s) as other compensation costs arising from services rendered by employees during the periodand to present the other components of net benefit cost in the income statement separately from the service cost component, and outside of operating income. The guidance also requires that an entity only capitalize the service cost component as part of an asset such as inventory or property, plant, and equipment on a prospective basis. Previously, all of the net benefit cost components were eligible for capitalization. The adoption of this guidance in the first quarter of 2018 may result in the recognition of new regulatory assets related to the recovery of, and return on, the non-service cost components of net benefit cost and related allowance for funds used during construction balances. We are currently assessing the impacts of this guidance on our results of operations, financial position, and disclosures.

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Derivative Financial Instruments Derivative Financial Instruments (Policies)

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

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

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

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

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

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Summary Of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Summary Of Nonvested Shares Related To Long-Term Incentive Plan

A summary of nonvested performance share units at March 31, 2017, and changes during the three months ended March 31, 2017, under the 2014 Incentive Plan are presented below:

	Performance Share Units
	Share Units		Weighted-average Fair Value per Share Unit
Nonvested at January 1, 2017	1,059,639		$	48.04
Granted(a)	496,068		59.16
Forfeitures	(3,192	)	49.13
Vested(b)	(3,779	)	52.88
Nonvested at March 31, 2017	1,548,736		$	51.59

(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 vary depending on actual performance over the three-year measurement period.

Schedule of Excise Taxes

The following table presents excise taxes recorded in “Operating Revenues – Electric,” “Operating Revenues – Gas” and “Operating Expenses – Taxes other than income taxes” for the three months ended March 31, 2017 and 2016:

	Three Months
	2017		2016
Ameren Missouri	$	31	$	30
Ameren Illinois	19		20
Ameren	$	50	$	50

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

3 Months Ended

Mar. 31, 2017

Schedule of Commercial paper [Abstract]

Schedule of Short-term Debt

The following table presents commercial paper outstanding as of March 31, 2017, and December 31, 2016:

	2017		2016
Ameren (parent)	$	810	$	507
Ameren Missouri	36		—
Ameren Illinois	68		51
Ameren Consolidated	$	914	$	558

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 three months ended March 31, 2017 and 2016:

	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated
2017
Average daily commercial paper outstanding	$	682		$	4		$	50		$	736
Weighted-average interest rate	1.07		%	0.93		%	0.95		%	1.06		%
Peak commercial paper during period(a)	$	810		$	45		$	74		$	914
Peak interest rate	1.30		%	1.15		%	1.15		%	1.30		%
2016
Average daily commercial paper outstanding	$	349		$	68		$	—		$	417
Weighted-average interest rate	0.82		%	0.80		%	—		%	0.81		%
Peak commercial paper during period(a)	$	482		$	208		$	—		$	581
Peak interest rate	0.95		%	0.85		%	—		%	0.95		%

(a) The timing of peak commercial paper issuances varies by company. Therefore, the sum of peak commercial paper issuances presented by company does not equal the Ameren Consolidated peak commercial paper issuances for the period.

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Other Income and Expenses (Tables)

3 Months Ended

Mar. 31, 2017

Other Nonoperating Income (Expense) [Abstract]

Other Income And Expenses

The following table presents the components of “Other Income and Expenses” in the Ameren Companies’ statements of income for the three months ended March 31, 2017 and 2016:

	Three Months
	2017	2016
Ameren:(a)
Miscellaneous income:

	Three Months
	2017		2016
Allowance for equity funds used during construction	$	6	$	8
Interest income on industrial development revenue bonds	7		7
Interest income	2		4
Other	—		1
Total miscellaneous income	$	15	$	20
Miscellaneous expense:
Donations	$	5	$	5
Other	4		2
Total miscellaneous expense	$	9	$	7
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	5	$	7
Interest income on industrial development revenue bonds	7		7
Other	—		1
Total miscellaneous income	$	12	$	15
Miscellaneous expense:
Donations	$	—	$	1
Other	2		1
Total miscellaneous expense	$	2	$	2
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	1	$	1
Interest income	2		4
Total miscellaneous income	$	3	$	5
Miscellaneous expense:
Donations	$	4	$	4
Other	2		1
Total miscellaneous expense	$	6	$	5

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

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Derivative Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Open Gross Derivative Volumes By Commodity Type

The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of March 31, 2017 and December 31, 2016. As of March 31, 2017, these contracts extended through October 2019, March 2023, May 2032, and February 2020 for fuel oils, natural gas, power, and uranium, respectively.

	Quantity (in millions, except as indicated)
	2017			2016
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)(a)	36	(b)	36	30	(b)	30
Natural gas (in mmbtu)	28	149	177	25	129	154
Power (in megawatthours)	1	9	10	1	9	10
Uranium (pounds in thousands)	345	(b)	345	345	(b)	345

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

(b) Not applicable.

Derivative Instruments Carrying Value

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 March 31, 2017 and December 31, 2016:

	Balance Sheet Location	Ameren Missouri			Ameren Illinois		Ameren
2017
Fuel oils	Other current assets	$	1		$	—	$	1
	Other assets	1			—		1
Natural gas	Other current assets	—			5		5
Power	Other current assets	5			—		5
	Total assets (a)	$	7		$	5	$	12
Fuel oils	Other current liabilities	$	5		$	—	$	5
Natural gas	MTM derivative liabilities	(b)			6		(b)
	Other current liabilities	2			—		8
	Other deferred credits and liabilities	6			9		15
Power	MTM derivative liabilities	(b)			12		(b)
	Other current liabilities	1			—		13
	Other deferred credits and liabilities	—			182		182
Uranium	Other deferred credits and liabilities	—		(c)	—		—		(c)
	Total liabilities (d)	$	14		$	209	$	223
2016
Fuel oils	Other current assets	$	2		$	—	$	2
	Other assets	1			—		1
Natural gas	Other current assets	1			11		12
	Other assets	1			2		3
Power	Other current assets	9			—		9
	Total assets (a)	$	14		$	13	$	27
Fuel oils	Other current liabilities	$	5		$	—	$	5
Natural gas	MTM derivative liabilities	(b)			3		(b)
	Other current liabilities	1			—		4
	Other deferred credits and liabilities	5			5		10
Power	MTM derivative liabilities	(b)			12		(b)
	Other current liabilities	3			—		15
	Other deferred credits and liabilities	—			173		173
Uranium	Other deferred credits and liabilities	4			—		4
	Total liabilities (d)	$	18		$	193	$	211

(a) 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) Beginning in 2017, as a result of rulebook amendments at the Chicago Mercantile Exchange, the fair value of uranium derivative liabilities are offset by certain settlement payments made to the exchange previously characterized as collateral and included within “Other assets” on Ameren’s and Ameren Missouri’s balance sheet.

(d) The cumulative amount of pretax net losses on all derivative instruments is deferred as a regulatory asset.

Derivative Instruments With Credit Risk-Related Contingent Features

The following table presents, as of March 31, 2017, 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 March 31, 2017, 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)
2017
Ameren Missouri	$	58	$	8	$	44
Ameren Illinois	38		—		30
Ameren	$	96	$	8	$	74

(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.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

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

The following table describes the valuation techniques and unobservable inputs 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 March 31, 2017 and December 31, 2016:

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
Level 3 Derivative asset and liability – commodity contracts(a):
2017
	Fuel oils	$	1	$	(1	)	Option model	Volatilities(%)(b)	23 – 35	27
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.12 – 0.22	0.15

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
								Ameren Missouri credit risk(%)(c)(d)	0.37	(e)
								Escalation rate (%)(b)(f)	0 – 1	0
	Natural gas	—		(2		)	Discounted cash flow	Nodal basis ($/mmbtu)(b)	(0.80) – (0.10)	(0.70)
								Counterparty credit risk (%)(c)(d)	0.45 – 6	0.70
								Ameren Illinois credit risk (%)(c)(d)	0.37	(e)
	Power(g)	5		(195		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)(h)	25 – 44	29
								Estimated auction price for FTRs ($/MW)(b)	(89) – 1,568	164
								Nodal basis ($/MWh)(h)	(4) – 0	(2)
								Ameren Illinois credit risk (%)(c)(d)	0.37	(e)
							Fundamental energy production model	Estimated future gas prices ($/mmbtu)(b)	3 – 4	3
								Escalation rate (%)(b)(i)	3	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(b)	5 – 7	6
2016
	Fuel oils	$	1	$	—		Option model	Volatilities (%)(b)	24 – 66	28
							Discounted cash flow	Counterparty credit risk (%)(c)(d)	0.13 – 0.22	0.15
								Ameren Missouri credit risk (%)(c)(d)	0.38	(e)
								Escalation rate (%)(b)(f)	(2) – 2	0
	Natural gas	1		(1		)	Option model	Volatilities (%)(b)	31 – 66	36
								Nodal basis ($/mmbtu)(b)	(0.40) – (0.10)	(0.20)
							Discounted cash flow	Nodal basis ($/mmbtu)(b)	(0.80) – 0	(0.50)
								Counterparty credit risk (%)(c)(d)	0.13 – 8	1
								Ameren Illinois credit risk (%)(c)(d)	0.38	(e)
	Power(g)	9		(187		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)(h)	26 – 44	29
								Estimated auction price for FTRs ($/MW)(b)	(71) – 5,270	125
								Nodal basis ($/MWh)(h)	(6) – 0	(2)
								Ameren Illinois credit risk (%)(c)(d)	0.38	(e)
							Fundamental energy production model	Estimated future gas prices ($/mmbtu)(b)	3 – 4	3
								Escalation rate (%)(b)(i)	5	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(b)	5 – 7	6
	Uranium	—		(4		)	Option model	Volatilities (%)(b)	24	(e)
							Discounted cash flow	Average forward uranium pricing ($/pound)(b)	22 – 24	22
								Ameren Missouri credit risk (%)(c)(d)	0.38	(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) Escalation rate applies to fuel oil prices 2019 and beyond

(g) Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2021 for March 31, 2017 and through 2020 for December 31, 2016. Valuations beyond 2021 for March 31, 2017 and 2020 for December 31, 2016 use fundamentally modeled pricing by month for peak and off-peak demand.

(h) 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.

(i) Escalation rate applies to power prices in 2031 and beyond.

Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of March 31, 2017:

		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable  Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
Ameren	Derivative assets – commodity contracts(a):
	Fuel oils	$	1	$	—	$	1	$	2
	Natural gas	1		4		—		5
	Power	—		—		5		5
	Total derivative assets – commodity contracts	$	2	$	4	$	6	$	12
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	420		—		—		420
	Debt securities:
	U.S. treasury and agency securities	—		118		—		118
	Corporate bonds	—		70		—		70
	Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	421	$	212	$	—	$	633	(b)
	Total Ameren	$	423	$	216	$	6	$	645
Ameren Missouri	Derivative assets – commodity contracts(a):
	Fuel oils	$	1	$	—	$	1	$	2
	Power	—		—		5		5
	Total derivative assets – commodity contracts	$	1	$	—	$	6	$	7
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	420		—		—		420
	Debt securities:
	U.S. treasury and agency securities	—		118		—		118
	Corporate bonds	—		70		—		70
	Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	421	$	212	$	—	$	633	(b)
	Total Ameren Missouri	$	422	$	212	$	6	$	640
Ameren Illinois	Derivative assets – commodity contracts(a):
	Natural gas	$	1	$	4	$	—	$	5
Liabilities:
Ameren	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	4	$	—	$	1	$	5
	Natural gas	—		21		2		23
	Power	—		—		195		195
	Total Ameren	$	4	$	21	$	198	$	223
Ameren Missouri	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	4	$	—	$	1	$	5
	Natural gas	—		8		—		8
	Power	—		—		1		1
	Total Ameren Missouri	$	4	$	8	$	2	$	14
Ameren Illinois	Derivative liabilities – commodity contracts(a):
	Natural gas	$	—	$	13	$	2	$	15
	Power	—		—		194		194
	Total Ameren Illinois	$	—	$	13	$	196	$	209

(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, 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
Assets:
Ameren	Derivative assets – commodity contracts(a):
	Fuel oils	$	2	$	—	$	1	$	3
	Natural gas	2		12		1		15
	Power	—		—		9		9
	Total derivative assets – commodity contracts	$	4	$	12	$	11	$	27
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	408		—		—		408
	Debt securities:
	U.S. treasury and agency securities	—		112		—		112
	Corporate bonds	—		67		—		67
	Other	—		17		—		17
	Total nuclear decommissioning trust fund	$	409	$	196	$	—	$	605	(b)
	Total Ameren	$	413	$	208	$	11	$	632
Ameren Missouri	Derivative assets – commodity contracts(a):
	Fuel oils	$	2	$	—	$	1	$	3
	Natural gas	—		1		1		2
	Power	—		—		9		9
	Total derivative assets – commodity contracts	$	2	$	1	$	11	$	14
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	408		—		—		408
	Debt securities:
	U.S. treasury and agency securities	—		112		—		112
	Corporate bonds	—		67		—		67
	Other	—		17		—		17
	Total nuclear decommissioning trust fund	$	409	$	196	$	—	$	605	(b)
	Total Ameren Missouri	$	411	$	197	$	11	$	619
Ameren Illinois	Derivative assets – commodity contracts(a):
	Natural gas	$	2	$	11	$	—	$	13
Liabilities:
Ameren	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	5	$	—	$	—	$	5
	Natural gas	—		13		1		14
	Power	—		1		187		188
	Uranium	—		—		4		4
	Total Ameren	$	5	$	14	$	192	$	211
Ameren Missouri	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	5	$	—	$	—	$	5
	Natural gas	—		6		—		6
	Power	—		1		2		3
	Uranium	—		—		4		4
	Total Ameren Missouri	$	5	$	7	$	6	$	18
Ameren Illinois	Derivative liabilities – commodity contracts(a):
	Natural gas	$	—	$	7	$	1	$	8
	Power	—		—		185		185
	Total Ameren Illinois	$	—	$	7	$	186	$	193

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

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

Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level Three In The Fair Value Hierarchy

The following table summarizes the changes in the fair value of power financial assets and liabilities classified as Level 3 in the fair value hierarchy:

		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
For the three months ended March 31, 2017
Beginning balance at January 1, 2017	$	7		$	(185	)	$	(178	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			(10	)		(10	)
Settlements		(3	)		1			(2	)
Ending balance at March 31, 2017	$	4		$	(194	)	$	(190	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2017	$	—		$	(11	)	$	(11	)
For the three months ended March 31, 2016
Beginning balance at January 1, 2016	$	16		$	(170	)	$	(154	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(3	)		(21	)		(24	)
Settlements		(7	)		4			(3	)
Ending balance at March 31, 2016	$	6		$	(187	)	$	(181	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2016	$	—		$	(19	)	$	(19	)

Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt, Capital Lease Obligations And Preferred Stock

The following table presents the carrying amounts and estimated fair values of our long-term debt, capital lease obligations and preferred stock at March 31, 2017 and December 31, 2016:

	March 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:
Long-term debt and capital lease obligations (including current portion)	$	7,278	$	7,762	$	7,276	$	7,772
Preferred stock(a)	142		129		142		131
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	3,995	$	4,312	$	3,994	$	4,304
Preferred stock	80		77		80		79
Ameren Illinois:
Long-term debt (including current portion)	$	2,588	$	2,742	$	2,588	$	2,765
Preferred stock	62		52		62		52

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

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three months ended March 31, 2017 and 2016:

				Three Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2017	$	11	$	(a)
agreements with Ameren Illinois		2016		9		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2017		7		1
rent and facility services		2016		6		1
Total Operating Revenues		2017	$	18	$	1
		2016		15		1
Ameren Illinois power supply	Purchased Power	2017	$	(a)	$	11
agreements with Ameren Missouri		2016		(a)		9
Ameren Illinois transmission	Purchased Power	2017		(a)		(b)
services with ATXI		2016		(a)		(b)
Total Purchased Power		2017	$	(a)	$	11
		2016		(a)		9
Ameren Services support services	Other Operations and Maintenance	2017	$	35	$	32
agreement		2016		34		31
Money pool borrowings (advances)	Interest Charges/ Miscellaneous Income	2017	$	(b)	$	(b)
		2016		(b)		(b)

(a) Not applicable.

(b) Amount less than $1 million.

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Callaway Energy Center (Tables)

3 Months Ended

Mar. 31, 2017

Nuclear Waste Matters [Abstract]

Schedule of Insurance Coverage at Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at March 31, 2017. The property coverage and the nuclear liability coverage renewal dates are April 1 and January 1, respectively, of each year. Both coverages were renewed in 2017.

Type and Source of Coverage	Maximum  Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	450		$	—
Pool participation	12,986		(a)	127		(b)
	$	13,436	(c)	$	127
Property damage:
NEIL and EMANI	$	3,200	(d)	$	29	(e)
Replacement power:
NEIL	$	490	(f)	$	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 $450 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. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.

(d) NEIL provides $2.7 billion in property damage, stabilization, decontamination, and premature decommissioning insurance for radiation events and $2.3 billion in property damage for nonradiation events. EMANI provides $490 million for both radiation and nonradiation events.

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

(f) 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 limited to $328 million.

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Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2017

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

Components Of Net Periodic Benefit Cost

The following table presents the components of the net periodic benefit cost (benefit) incurred for Ameren’s pension and postretirement benefit plans for the three months ended March 31, 2017 and 2016:

	Pension Benefits						Postretirement Benefits
	Three Months						Three Months
	2017			2016			2017			2016
Service cost	$	23		$	20		$	5		$	5
Interest cost	45			47			12			12
Expected return on plan assets	(66		)	(63		)	(19		)	(18		)
Amortization of:
Prior service benefit	—			—			(1		)	(1		)
Actuarial loss (gain)	14			9			(2		)	(3		)
Net periodic benefit cost (benefit)	$	16		$	13		$	(5	)	$	(5	)

Summary Of Benefit Plan Costs Incurred

Ameren Missouri and Ameren Illinois are responsible for their respective shares of Ameren’s pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs (benefit) incurred for the three months ended March 31, 2017 and 2016:

	Pension Benefits				Postretirement Benefits
	Three Months				Three Months
	2017		2016		2017			2016
Ameren Missouri(a)	$	6	$	8	$	(1	)	$	(1	)
Ameren Illinois	10		5		(4		)	(4		)
Ameren(a)(b)	$	16	$	13	$	(5	)	$	(5	)

(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.

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Schedule Of Segment Reporting Information By Segment

The following tables present information about the reported revenues and specified items reflected in net income attributable to common shareholders and capital expenditures at Ameren and Ameren Illinois for the three months ended March 31,2017 and 2016. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.

Ameren

Three Months	Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission			Other				Intersegment Eliminations			Consolidated
2017
External revenues	$	772	$	384	$	264	$	96		$	(2	)		$	—		$	1,514
Intersegment revenues	18		1		—		6		(a)	—				(25		)	—
Net income attributable to Ameren common shareholders	5		30		33		34			—				—			102
Capital expenditures	196		120		51		134			4			(b)	(1		)	504
2016
External revenues	$	726	$	351	$	285	$	72		$	—			$	—		$	1,434
Intersegment revenues	15		1		—		11		(a)	—				(27		)	—
Net income attributable to Ameren common shareholders	14		11		35		27			18				—			105
Capital expenditures	178		117		35		164			2			(b)	—			496

(a) Ameren Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above.

(b) Includes the elimination of intercompany transfers.    

Ameren Illinois

	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission			Intersegment Eliminations			Consolidated
2017
External revenues	$	385	$	264	$	54		$	—		$	703
Intersegment revenues	—		—		6		(a)	(6		)	—
Net income available to common shareholder	30		33		16			—			79
Capital expenditures	120		51		56			—			227
2016
External revenues	$	352	$	285	$	40		$	—		$	677
Intersegment revenues	—		—		11		(a)	(11		)	—
Net income available to common shareholder	11		35		13			—			59
Capital expenditures	117		35		59			—			211

(a) Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above.

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Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Summary of Nonvested Shares Related To Long-Term Incentive Plan) (Details) - $ / shares		3 Months Ended
		Mar. 31, 2017	Dec. 31, 2016
Weighted-average Fair Value per Unit at Grant Date
Closing common share price			$ 52.46
Performance Shares
Share Units
Share Units, Nonvested as of beginning of year		1,059,639
Share Units, Granted	[1]	496,068
Share Units, Forfeitures		(3,192)
Share Units, Vested	[2]	(3,779)
Share Units, Nonvested as of Current period end		1,548,736
Weighted-average Fair Value per Unit at Grant Date
Weighted-average Fair Value per Unit, Nonvested as of Beginning of year		$ 48.04
Weighted-average Fair Value per Unit, Grants	[1]	59.16
Weighted-average Fair Value per Unit, Forfeitures		49.13
Weighted-average Fair Value per Unit, Vested	[2]	52.88
Weighted-average Fair Value per Unit, Nonvested as of Current period end		$ 51.59
Performance period		3 years
Risk free interest rate period		3 years
Three-year risk-free rate		1.47%
Volatility rate, minimum		15.00%
Volatility rate, maximum		21.00%

[1] Performance share units granted to certain executive and nonexecutive officers and other eligible employees under the 2014 Incentive Plan.

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

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Summary Of Significant Accounting Policies (Schedule Of Excise Taxes) (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Accounting Policies [Line Items]
Excise tax expense	$ 50	$ 50
Union Electric Company
Accounting Policies [Line Items]
Excise tax expense	31	30
Ameren Illinois Company
Accounting Policies [Line Items]
Excise tax expense	$ 19	$ 20

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Rate And Regulatory Matters (Narrative-Missouri) (Detail) - Electric Distribution - Union Electric Company $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Final Rate Order [Member]
Rate And Regulatory Matters [Line Items]
Revenue Requirement	$ 3,400
Public Utilities, Requested Rate Increase (Decrease), Amount	92
Components of Rate Increase - Net Energy Costs [Member]
Rate And Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	54
Components of Rate Increase - Regulatory Amortizations [Member]
Rate And Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 26

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Rate And Regulatory Matters (Narrative-Illinois) (Detail) - USD ($) $ in Millions	3 Months Ended
	Jun. 30, 2017	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Rate And Regulatory Matters [Line Items]
Regulatory assets		$ 1,485		$ 1,437
Current regulatory assets		118		149
Electric		1,206	$ 1,102
Ameren Illinois Company
Rate And Regulatory Matters [Line Items]
Regulatory assets		875		816
Current regulatory assets		91		$ 108
Electric		439	392
IEIMA | Ameren Illinois Company | Electric Distribution
Rate And Regulatory Matters [Line Items]
Electric		46	$ 11
2016 IEIMA Revenue Requirement Reconciliation [Member] | IEIMA | Ameren Illinois Company | Electric Distribution
Rate And Regulatory Matters [Line Items]
Regulatory assets		24
2015 IEIMA Revenue Requirement Reconciliation | IEIMA | Ameren Illinois Company | Electric Distribution
Rate And Regulatory Matters [Line Items]
Current regulatory assets		54
2014 IEIMA Revenue Requirement Reconciliation | IEIMA | Ameren Illinois Company | Electric Distribution
Rate And Regulatory Matters [Line Items]
Regulatory assets		$ 46
FEJA [Member] | Ameren Illinois Company | Electric Distribution
Rate And Regulatory Matters [Line Items]
Public Utilities, Requested Equity Capital Structure, Percentage		50.00%
Subsequent Event | Pending Rate Case | IEIMA | Ameren Illinois Company | Electric Distribution
Rate And Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 16

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Rate And Regulatory Matters (Narrative-Federal) (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Rate And Regulatory Matters [Line Items]
Current regulatory liabilities	$ 144	$ 110
Ameren Illinois Company
Rate And Regulatory Matters [Line Items]
Current regulatory liabilities	$ 118	$ 78
Midwest Independent Transmission System Operator, Inc
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Return on Equity, Percentage	12.38%
Midwest Independent Transmission System Operator, Inc | Final Rate Order [Member]
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Return on Equity, Percentage	10.32%
Customer Requested Rate on Equity	9.15%
Payments for Legal Settlements	$ 21
Incentive adder to FERC allowed base return on common equity	0.50%
Midwest Independent Transmission System Operator, Inc | Final Rate Order [Member] | Ameren Illinois Company
Rate And Regulatory Matters [Line Items]
Payments for Legal Settlements	$ 17
Midwest Independent Transmission System Operator, Inc | Administrative Law Judge
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Return on Equity, Percentage	9.70%
Midwest Independent Transmission System Operator, Inc | Pending Ferc Case
Rate And Regulatory Matters [Line Items]
Current regulatory liabilities	$ 41
Midwest Independent Transmission System Operator, Inc | Pending Ferc Case | Ameren Illinois Company
Rate And Regulatory Matters [Line Items]
Current regulatory liabilities	$ 24
Maximum | Midwest Independent Transmission System Operator, Inc | Final Rate Order [Member]
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Return on Equity, Percentage	10.82%
Maximum | Midwest Independent Transmission System Operator, Inc | Administrative Law Judge
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Return on Equity, Percentage	10.20%

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Short-Term Debt And Liquidity (Narrative) (Detail) $ in Billions	3 Months Ended
	Mar. 31, 2017 USD ($)	Mar. 31, 2016
Utilities
Line of Credit Facility [Line Items]
Short Term Debt, Weighted Average Interest Rate During Period	1.01%	0.47%
Credit Agreements 2012
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 1.2
Actual debt-to-capital ratio	0.53
Missouri Credit Agreement 2012 | Union Electric Company
Line of Credit Facility [Line Items]
Actual debt-to-capital ratio	0.48
Illinois Credit Agreement 2012 | Ameren Illinois Company
Line of Credit Facility [Line Items]
Actual debt-to-capital ratio	0.46

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Short-Term Debt And Liquidity Short-Term Debt and Liquidity (Commercial Paper outstanding) (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Commercial paper outstanding	$ 914	$ 558
Ameren (parent)
Line of Credit Facility [Line Items]
Commercial paper outstanding	810	507
Union Electric Company
Line of Credit Facility [Line Items]
Commercial paper outstanding	36	0
Ameren Illinois Company
Line of Credit Facility [Line Items]
Commercial paper outstanding	$ 68	$ 51

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Short-Term Debt And Liquidity Short-Term Debt and Liquidity (Commercial Paper) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Line of Credit Facility [Line Items]
Average Daily Commercial Paper Borrowings Outstanding		$ 736	$ 417
Weighted Average Interest Rate		1.06%	0.81%
Peak Short Term Borrowings	[1]	$ 914	$ 581
Peak Short Term Borrowings Interest Rate		1.30%	0.95%
Ameren (parent)
Line of Credit Facility [Line Items]
Average Daily Commercial Paper Borrowings Outstanding		$ 682	$ 349
Weighted Average Interest Rate		1.07%	0.82%
Peak Short Term Borrowings	[1]	$ 810	$ 482
Peak Short Term Borrowings Interest Rate		1.30%	0.95%
Union Electric Company
Line of Credit Facility [Line Items]
Average Daily Commercial Paper Borrowings Outstanding		$ 4	$ 68
Weighted Average Interest Rate		0.93%	0.80%
Peak Short Term Borrowings	[1]	$ 45	$ 208
Peak Short Term Borrowings Interest Rate		1.15%	0.85%
Ameren Illinois Company
Line of Credit Facility [Line Items]
Average Daily Commercial Paper Borrowings Outstanding		$ 50	$ 0
Weighted Average Interest Rate		0.95%	0.00%
Peak Short Term Borrowings	[1]	$ 74	$ 0
Peak Short Term Borrowings Interest Rate		1.15%	0.00%

[1] (a)The timing of peak commercial paper issuances varies by company. Therefore, the sum of peak commercial paper issuances presented by company does not equal the Ameren Consolidated peak commercial paper issuances for the period.

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Other Income and Expenses (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Other Nonoperating Income (Expense) [Line Items]
Allowance for equity funds used during construction	[1]	$ 6	$ 8
Interest income on industrial development revenue bonds	[1]	7	7
Interest income	[1]	2	4
Other	[1]	0	1
Total miscellaneous income	[1]	15	20
Donations	[1]	5	5
Other	[1]	4	2
Total miscellaneous expense	[1]	9	7
Union Electric Company
Other Nonoperating Income (Expense) [Line Items]
Allowance for equity funds used during construction		5	7
Interest income on industrial development revenue bonds		7	7
Other		0	1
Total miscellaneous income		12	15
Donations		0	1
Other		2	1
Total miscellaneous expense		2	2
Ameren Illinois Company
Other Nonoperating Income (Expense) [Line Items]
Allowance for equity funds used during construction		1	1
Interest income		2	4
Total miscellaneous income		3	5
Donations		4	4
Other		2	1
Total miscellaneous expense		$ 6	$ 5

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

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Derivative Financial Instruments (Open Gross Derivative Volumes By Commodity Type) (Detail) lb in Thousands, gal in Millions, MWh in Millions, MMBTU in Millions		Mar. 31, 2017 gal MWh MMBTU lb	Dec. 31, 2016 gal MWh MMBTU lb
Fuel Oils
Derivative [Line Items]
Quantity | gal	[1]	36	30
Natural Gas
Derivative [Line Items]
Quantity | MMBTU		177	154
Power
Derivative [Line Items]
Quantity | MWh		10	10
Uranium
Derivative [Line Items]
Quantity | lb		345	345
Union Electric Company | Fuel Oils
Derivative [Line Items]
Quantity | gal	[1]	36	30
Union Electric Company | Natural Gas
Derivative [Line Items]
Quantity | MMBTU		28	25
Union Electric Company | Power
Derivative [Line Items]
Quantity | MWh		1	1
Union Electric Company | Uranium
Derivative [Line Items]
Quantity | lb		345	345
Ameren Illinois Company | Natural Gas
Derivative [Line Items]
Quantity | MMBTU		149	129
Ameren Illinois Company | Power
Derivative [Line Items]
Quantity | MWh		9	9

[1] Consists of ultra-low-sulfur diesel products.

XML

Derivative Financial Instruments (Derivative Instruments Carrying Value) (Detail) - Not Designated As Hedging Instrument - USD ($) $ in Millions		Mar. 31, 2017		Dec. 31, 2016
Derivative [Line Items]
Derivative assets	[1]	$ 12		$ 27
Derivative liabilities	[2]	223		211
Fuel Oils | Other Current Assets
Derivative [Line Items]
Derivative assets		1		2
Fuel Oils | Other Assets
Derivative [Line Items]
Derivative assets		1		1
Fuel Oils | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities		5		5
Natural Gas | Other Current Assets
Derivative [Line Items]
Derivative assets		5		12
Natural Gas | Other Assets
Derivative [Line Items]
Derivative assets				3
Natural Gas | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities		8		4
Natural Gas | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities		15		10
Power | Other Current Assets
Derivative [Line Items]
Derivative assets		5		9
Power | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities		13		15
Power | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities		182		173
Uranium | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities		0	[3]	4
Union Electric Company
Derivative [Line Items]
Derivative assets	[1]	7		14
Derivative liabilities	[2]	14		18
Union Electric Company | Fuel Oils | Other Current Assets
Derivative [Line Items]
Derivative assets		1		2
Union Electric Company | Fuel Oils | Other Assets
Derivative [Line Items]
Derivative assets		1		1
Union Electric Company | Fuel Oils | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities		5		5
Union Electric Company | Natural Gas | Other Current Assets
Derivative [Line Items]
Derivative assets				1
Union Electric Company | Natural Gas | Other Assets
Derivative [Line Items]
Derivative assets				1
Union Electric Company | Natural Gas | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities		2		1
Union Electric Company | Natural Gas | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities		6		5
Union Electric Company | Power | Other Current Assets
Derivative [Line Items]
Derivative assets		5		9
Union Electric Company | Power | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities		1		3
Union Electric Company | Power | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities		0		0
Union Electric Company | Uranium | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities		0	[3]	4
Ameren Illinois Company
Derivative [Line Items]
Derivative assets	[1]	5		13
Derivative liabilities	[2]	209		193
Ameren Illinois Company | Fuel Oils | Other Current Assets
Derivative [Line Items]
Derivative assets		0		0
Ameren Illinois Company | Fuel Oils | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities		0		0
Ameren Illinois Company | Natural Gas | Other Current Assets
Derivative [Line Items]
Derivative assets		5		11
Ameren Illinois Company | Natural Gas | Other Assets
Derivative [Line Items]
Derivative assets				2
Ameren Illinois Company | Natural Gas | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities		0		0
Ameren Illinois Company | Natural Gas | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities		9		5
Ameren Illinois Company | Natural Gas | Mark To Market Derivative Liabilities
Derivative [Line Items]
Derivative liabilities		6		3
Ameren Illinois Company | Power | Other Current Assets
Derivative [Line Items]
Derivative assets		0		0
Ameren Illinois Company | Power | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities		0		0
Ameren Illinois Company | Power | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities		182		173
Ameren Illinois Company | Power | Mark To Market Derivative Liabilities
Derivative [Line Items]
Derivative liabilities		12		12
Ameren Illinois Company | Uranium | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities		$ 0		$ 0

[1] The cumulative amount of pretax net gains on all derivative instruments is deferred as a regulatory liability.

[2] The cumulative amount of pretax net losses on all derivative instruments is deferred as a regulatory asset.

[3] {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjRjZDVlNzcwZmZkOTQxZjliMGIxYmE1N2RmYzJmN2QxfFRleHRTZWxlY3Rpb246QThFRjZENDY4MDM0NTAxRkExNkVGNzQzMEE3QjMyNDIM}

XML

Derivative Financial Instruments (Derivative Instruments With Credit Risk-Related Contingent Features) (Detail) $ in Millions	Mar. 31, 2017 USD ($)
Derivative [Line Items]
Aggregate Fair Value of Derivative Liabilities	$ 96	[1]
Cash Collateral Posted	8
Potential Aggregate Amount of Additional Collateral Required	74	[2]
Union Electric Company
Derivative [Line Items]
Aggregate Fair Value of Derivative Liabilities	58	[1]
Cash Collateral Posted	8
Potential Aggregate Amount of Additional Collateral Required	44	[2]
Ameren Illinois Company
Derivative [Line Items]
Aggregate Fair Value of Derivative Liabilities	38	[1]
Cash Collateral Posted	0
Potential Aggregate Amount of Additional Collateral Required	$ 30	[2]

[1] Before consideration of master netting arrangements or similar agreements and including NPNS and other accrual contract exposures.

[2] 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.

XML

Fair Value Measurements (Schedule Of Valuation Process And Unobservable Inputs) (Detail) $ in Millions		3 Months Ended	12 Months Ended
		Mar. 31, 2017 USD ($) $ / credit $ / MMBTU $ / MWh $ / MW	Dec. 31, 2016 USD ($) $ / credit $ / MMBTU $ / lb $ / MWh $ / MW
Natural Gas | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Counterparty credit risk	[1],[2]	0.45%	0.13%
Nodal basis	[3]	(0.80)	(0.8)
Credit risk	[1],[2]	0.37%	0.38%
Natural Gas | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Counterparty credit risk	[1],[2]	6.00%	8.00%
Nodal basis	[3]	(0.1)	0
Credit risk	[1],[2]	0.37%	0.38%
Natural Gas | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Counterparty credit risk	[1],[2]	0.70%	1.00%
Nodal basis	[3]	(0.70)	(0.5)
Credit risk	[1],[2]	0.37%	0.38%
Natural Gas | Option Model | Minimum
Fair Value Inputs [Abstract]
Volatilities	[3]		31.00%
Nodal basis	[3]		(0.40)
Natural Gas | Option Model | Maximum
Fair Value Inputs [Abstract]
Volatilities	[3]		66.00%
Nodal basis	[3]		(0.1)
Natural Gas | Option Model | Weighted Average
Fair Value Inputs [Abstract]
Volatilities	[3]		36.00%
Nodal basis	[3]		(0.20)
Natural Gas | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets | $	[4]	$ 0	$ 1
Natural Gas | Derivative Liabilities
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities | $	[4]	$ (2)	$ (1)
Fuel Oils | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Escalation rate	[3],[5]		(2.00%)
Counterparty credit risk	[1],[2]	0.12%	0.13%
Credit risk	[1],[2]	0.37%	0.38%
Fuel Oils | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Escalation rate	[3],[5]	1.00%	2.00%
Counterparty credit risk	[1],[2]	0.22%	0.22%
Credit risk	[1],[2]	0.37%	0.38%
Fuel Oils | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Counterparty credit risk	[1],[2]	0.15%	0.15%
Credit risk	[1],[2]	0.37%	0.38%
Fuel Oils | Option Model | Minimum
Fair Value Inputs [Abstract]
Volatilities	[3]	23.00%	24.00%
Fuel Oils | Option Model | Maximum
Fair Value Inputs [Abstract]
Volatilities	[3]	35.00%	66.00%
Fuel Oils | Option Model | Weighted Average
Fair Value Inputs [Abstract]
Volatilities	[3]	27.00%	28.00%
Fuel Oils | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets | $	[4]	$ 1	$ 1
Fuel Oils | Derivative Liabilities
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities | $	[4]	$ (1)
Power | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Nodal basis | $ / MWh	[6]	(4)	(6)
Credit risk	[1],[2]	0.37%	0.38%
Average forward peak and off-peak pricing | $ / MWh	[6]	25	26
Estimated auction price | $ / MW	[3]	(89)	(71)
Power | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Nodal basis | $ / MWh	[6]	0	0
Credit risk	[1],[2]	0.37%	0.38%
Average forward peak and off-peak pricing | $ / MWh	[6]	44	44
Estimated auction price | $ / MW	[3]	1,568	5,270
Power | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Nodal basis | $ / MWh	[6]	(2)	(2)
Credit risk	[1],[2]	0.37%	0.38%
Average forward peak and off-peak pricing | $ / MWh	[6]	29	29
Estimated auction price | $ / MW	[3]	164	125
Power | Fundamental Energy Production Model | Minimum
Fair Value Inputs [Abstract]
Escalation rate	[3],[7]	3.00%	3.00%
Estimated future gas prices	[3]	3	3
Power | Fundamental Energy Production Model | Maximum
Fair Value Inputs [Abstract]
Escalation rate	[3],[7]	3.00%	3.00%
Estimated future gas prices	[3]	4	4
Power | Fundamental Energy Production Model | Weighted Average
Fair Value Inputs [Abstract]
Escalation rate	[3],[7]	3.00%	3.00%
Estimated future gas prices	[3]	3	3
Power | Contract Price Allocation | Minimum
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs | $ / credit	[3]	5	5
Power | Contract Price Allocation | Maximum
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs | $ / credit	[3]	7	7
Power | Contract Price Allocation | Weighted Average
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs | $ / credit	[3]	6	6
Power | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets | $	[4],[8]	$ 5	$ 9
Power | Derivative Liabilities
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities | $	[4],[8]	$ (195)	$ (187)
Uranium | Discounted Cash Flow | Minimum
Fair Value Inputs [Abstract]
Credit risk	[1],[2]		0.38%
Average forward pricing | $ / lb	[3]		22
Uranium | Discounted Cash Flow | Maximum
Fair Value Inputs [Abstract]
Credit risk	[1],[2]		0.38%
Average forward pricing | $ / lb	[3]		24
Uranium | Discounted Cash Flow | Weighted Average
Fair Value Inputs [Abstract]
Credit risk	[1],[2]		0.38%
Average forward pricing | $ / lb	[3]		22
Uranium | Option Model | Minimum
Fair Value Inputs [Abstract]
Volatilities	[3]		24.00%
Uranium | Option Model | Maximum
Fair Value Inputs [Abstract]
Volatilities	[3]		24.00%
Uranium | Option Model | Weighted Average
Fair Value Inputs [Abstract]
Volatilities	[3]		24.00%
Uranium | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets | $	[4]		$ 0
Uranium | Derivative Liabilities
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities | $	[4]		$ (4)

[1] 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.

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

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

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

[5] Escalation rate applies to fuel oil prices 2019 and beyond

[6] 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.

[7] Escalation rate applies to power prices in 2031 and beyond.

[8] Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2021 for March 31, 2017 and through 2020 for December 31, 2016. Valuations beyond 2021 for March 31, 2017 and 2020 for December 31, 2016 use fundamentally modeled pricing by month for peak and off-peak demand.

XML

Fair Value Measurements (Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis) (Detail) - USD ($) $ in Millions		Mar. 31, 2017		Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		$ 633	[1]	$ 605	[2]
Assets fair value		645	[3]	632	[4]
Excluded receivables, payables, and accrued income, net		2		2
Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		633	[1]	605	[2]
Assets fair value		640	[3]	619	[4]
Excluded receivables, payables, and accrued income, net		2		(1)
Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		12	[3]	27	[4]
Derivative liabilities		223	[3]	211	[4]
Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		7	[3]	14	[4]
Derivative liabilities		14	[3]	18	[4]
Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities		209	[3]	193	[4]
Cash and cash equivalents
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		1		1
Cash and cash equivalents | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		1		1
Equity Securities | U.S. large capitalization
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		420		408
Equity Securities | U.S. large capitalization | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		420		408
Debt Securities | Corporate bonds
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		70		67
Debt Securities | Corporate bonds | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		70		67
Debt Securities | US treasury and government securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		118		112
Debt Securities | US treasury and government securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		118		112
Debt Securities | Other Debt Securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		24		17
Debt Securities | Other Debt Securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		24		17
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		421		409
Assets fair value		423	[3]	413	[4]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		421		409
Assets fair value		422	[3]	411	[4]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		2	[3]	4	[4]
Derivative liabilities		4	[3]	5	[4]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		1	[3]	2	[4]
Derivative liabilities		4	[3]	5	[4]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities		0	[3]	0	[4]
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Cash and cash equivalents
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		1		1
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Cash and cash equivalents | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		1		1
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Equity Securities | U.S. large capitalization
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		420		408
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Equity Securities | U.S. large capitalization | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		420		408
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Debt Securities | Corporate bonds
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Debt Securities | Corporate bonds | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Debt Securities | US treasury and government securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Debt Securities | US treasury and government securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Debt Securities | Other Debt Securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Debt Securities | Other Debt Securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Observable Inputs (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		212		196
Assets fair value		216	[3]	208	[4]
Significant Other Observable Inputs (Level 2) | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		212		196
Assets fair value		212	[3]	197	[4]
Significant Other Observable Inputs (Level 2) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		4	[3]	12	[4]
Derivative liabilities		21	[3]	14	[4]
Significant Other Observable Inputs (Level 2) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		0	[3]	1	[4]
Derivative liabilities		8	[3]	7	[4]
Significant Other Observable Inputs (Level 2) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities		13	[3]	7	[4]
Significant Other Observable Inputs (Level 2) | Cash and cash equivalents
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Observable Inputs (Level 2) | Cash and cash equivalents | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Observable Inputs (Level 2) | Equity Securities | U.S. large capitalization
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Observable Inputs (Level 2) | Equity Securities | U.S. large capitalization | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Observable Inputs (Level 2) | Debt Securities | Corporate bonds
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		70		67
Significant Other Observable Inputs (Level 2) | Debt Securities | Corporate bonds | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		70		67
Significant Other Observable Inputs (Level 2) | Debt Securities | US treasury and government securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		118		112
Significant Other Observable Inputs (Level 2) | Debt Securities | US treasury and government securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		118		112
Significant Other Observable Inputs (Level 2) | Debt Securities | Other Debt Securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		24		17
Significant Other Observable Inputs (Level 2) | Debt Securities | Other Debt Securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		24		17
Significant Other Unobservable Inputs (Level 3)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Assets fair value		6	[3]	11	[4]
Significant Other Unobservable Inputs (Level 3) | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Assets fair value		6	[3]	11	[4]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		6	[3]	11	[4]
Derivative liabilities		198	[3]	192	[4]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		6	[3]	11	[4]
Derivative liabilities		2	[3]	6	[4]
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities		196	[3]	186	[4]
Significant Other Unobservable Inputs (Level 3) | Cash and cash equivalents
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Unobservable Inputs (Level 3) | Cash and cash equivalents | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Unobservable Inputs (Level 3) | Equity Securities | U.S. large capitalization
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Unobservable Inputs (Level 3) | Equity Securities | U.S. large capitalization | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Unobservable Inputs (Level 3) | Debt Securities | Corporate bonds
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Unobservable Inputs (Level 3) | Debt Securities | Corporate bonds | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Unobservable Inputs (Level 3) | Debt Securities | US treasury and government securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Unobservable Inputs (Level 3) | Debt Securities | US treasury and government securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Unobservable Inputs (Level 3) | Debt Securities | Other Debt Securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Significant Other Unobservable Inputs (Level 3) | Debt Securities | Other Debt Securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		0		0
Uranium | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	[4]			4
Uranium | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	[4]			4
Uranium | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	[4]			0
Uranium | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	[4]			0
Uranium | Significant Other Observable Inputs (Level 2) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	[4]			0
Uranium | Significant Other Observable Inputs (Level 2) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	[4]			0
Uranium | Significant Other Unobservable Inputs (Level 3) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	[4]			4
Uranium | Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	[4]			4
Fuel Oils | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		2	[3]	3	[4]
Derivative liabilities		5	[3]	5	[4]
Fuel Oils | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		2	[3]	3	[4]
Derivative liabilities		5	[3]	5	[4]
Fuel Oils | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		1	[3]	2	[4]
Derivative liabilities		4	[3]	5	[4]
Fuel Oils | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		1	[3]	2	[4]
Derivative liabilities		4	[3]	5	[4]
Fuel Oils | Significant Other Observable Inputs (Level 2) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		0	[3]	0	[4]
Derivative liabilities		0	[3]	0	[4]
Fuel Oils | Significant Other Observable Inputs (Level 2) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		0	[3]	0	[4]
Derivative liabilities		0	[3]	0	[4]
Fuel Oils | Significant Other Unobservable Inputs (Level 3) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		1	[3]	1	[4]
Derivative liabilities		1	[3]	0	[4]
Fuel Oils | Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		1	[3]	1	[4]
Derivative liabilities		1	[3]	0	[4]
Power | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		5	[3]	9	[4]
Derivative liabilities		195	[3]	188	[4]
Power | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		5	[3]	9	[4]
Derivative liabilities		1	[3]	3	[4]
Power | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities		194	[3]	185	[4]
Power | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		0	[3]	0	[4]
Derivative liabilities		0	[3]	0	[4]
Power | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		0	[3]	0	[4]
Derivative liabilities		0	[3]	0	[4]
Power | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities		0	[3]	0	[4]
Power | Significant Other Observable Inputs (Level 2) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		0	[3]	0	[4]
Derivative liabilities		0	[3]	1	[4]
Power | Significant Other Observable Inputs (Level 2) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		0	[3]	0	[4]
Derivative liabilities		0	[3]	1	[4]
Power | Significant Other Observable Inputs (Level 2) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities		0	[3]	0
Power | Significant Other Unobservable Inputs (Level 3) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		5	[3]	9	[4]
Derivative liabilities		195	[3]	187	[4]
Power | Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		5	[3]	9	[4]
Derivative liabilities		1	[3]	2	[4]
Power | Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities		194	[3]	185	[4]
Natural Gas | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		5	[3]	15	[4]
Derivative liabilities		23	[3]	14	[4]
Natural Gas | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	[4]			2
Derivative liabilities		8	[3]	6	[4]
Natural Gas | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		5	[3]	13	[4]
Derivative liabilities		15	[3]	8	[4]
Natural Gas | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		1	[3]	2	[4]
Derivative liabilities		0	[3]	0	[4]
Natural Gas | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	[4]			0
Derivative liabilities		0	[3]	0	[4]
Natural Gas | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		1	[3]	2	[4]
Derivative liabilities		0	[3]	0	[4]
Natural Gas | Significant Other Observable Inputs (Level 2) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		4	[3]	12	[4]
Derivative liabilities		21	[3]	13	[4]
Natural Gas | Significant Other Observable Inputs (Level 2) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	[4]			1
Derivative liabilities		8	[3]	6	[4]
Natural Gas | Significant Other Observable Inputs (Level 2) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		4	[3]	11	[4]
Derivative liabilities		13	[3]	7	[4]
Natural Gas | Significant Other Unobservable Inputs (Level 3) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	[4]			1
Derivative liabilities		2	[3]	1	[4]
Natural Gas | Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	[4]			1
Derivative liabilities	[3]	0
Natural Gas | Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		0	[3]	0	[4]
Derivative liabilities		$ 2	[3]	$ 1	[4]

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

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

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

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

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Fair Value Measurements (Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level Three In The Fair Value Hierarchy) (Detail) - Power - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	$ (190)	$ (181)	$ (178)	$ (154)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Included in regulatory assets/liabilities	(10)	(24)
Settlements	(2)	(3)
Change in unrealized gains (losses) related to assets/liabilities held at period end	(11)	(19)
Union Electric Company
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	7	16
Included in regulatory assets/liabilities	0	(3)
Settlements	(3)	(7)
Ending balance	4	6
Change in unrealized gains (losses) related to assets/liabilities held at period end	0	0
Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	(194)	(187)	$ (185)	$ (170)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Included in regulatory assets/liabilities	(10)	(21)
Settlements	1	4
Change in unrealized gains (losses) related to assets/liabilities held at period end	$ (11)	$ (19)

XML

Fair Value Measurements (Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt And Preferred Stock) (Detail) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	[1]	$ 7,762	$ 7,772
Preferred stock	[1]	129	131
Fair Value | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)		4,312	4,304
Preferred stock		77	79
Fair Value | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)		2,742	2,765
Preferred stock		52	52
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)	[1]	7,278	7,276
Preferred stock	[1]	142	142
Carrying Amount | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)		3,995	3,994
Preferred stock		80	80
Carrying Amount | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt (including current portion)		2,588	2,588
Preferred stock		$ 62	$ 62

[1] Preferred stock is recorded in “Noncontrolling Interests” on the consolidated balance sheet.

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Related Party Transactions (Schedule of Related Party Transactions) (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Revenues		$ 0	$ 0
Purchased Power | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Expenses		11	9
Ameren Missouri Power Supply Agreements with Ameren Illinois | Union Electric Company
Related Party Transaction [Line Items]
Operating Revenues		11	9
Ameren Missouri and Ameren Illinois Rent and Facility Services | Union Electric Company
Related Party Transaction [Line Items]
Operating Revenues		7	6
Ameren Missouri and Ameren Illinois Rent and Facility Services | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Revenues		1	1
Total Related Party Operating Revenues [Member] | Union Electric Company
Related Party Transaction [Line Items]
Operating Revenues		18	15
Total Related Party Operating Revenues [Member] | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Revenues		1	1
Ameren Illinois Power Supply Agreements with Ameren Missouri | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Expenses		11	9
Ameren Illinois Transmission Agreements with ATXI | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Revenues	[1]	1	1
Ameren Services Support Services Agreement | Union Electric Company
Related Party Transaction [Line Items]
Operating Expenses		35	34
Ameren Services Support Services Agreement | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Expenses		32	31
Related Party Money Pool Interest | Union Electric Company
Related Party Transaction [Line Items]
Interest Charges	[1]	1	1
Related Party Money Pool Interest | Ameren Illinois Company
Related Party Transaction [Line Items]
Interest Charges	[1]	$ 1	$ 1

[1] Amount less than $1 million.

XML

Related Party Transactions Narrative (Details) - April 2017 Procurement [Member] - Ameren Illinois Company - Ameren Illinois Power Supply Agreements with Ameren Missouri	3 Months Ended
	Mar. 31, 2017 MWh $ / MWh
Related Party Transaction [Line Items]
Long-term Contract for Purchase of Electric Power, Related Party Contract, Fixed Power | MWh	85,600
Long-term Contract for Purchase of Electric Power, Related Party Contract, Fixed Power, Rate | $ / MWh	33.64

XML

Commitments And Contingencies (Other Obligations) (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) MWh
Long-term Purchase Commitment [Line Items]
Total Other Obligations	$ 3,824
Union Electric Company
Long-term Purchase Commitment [Line Items]
Total Other Obligations	2,340
Ameren Illinois Company
Long-term Purchase Commitment [Line Items]
Total Other Obligations	$ 1,418
April 2017 Procurement [Member] | Ameren Illinois Company
Long-term Purchase Commitment [Line Items]
Amount of Megawatthours | MWh	4,249,800
Long-term Purchase Commitment, Amount	$ 128

XML

Commitments And Contingencies (Environmental Matters) (Detail) $ in Millions	Mar. 31, 2017 USD ($) scrubber site	Dec. 31, 2016
Loss Contingencies [Line Items]
Percentage of Rate Base Related to Carbon Dioxide Energy Centers		18.00%
Minimum
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	$ 425.0
Maximum
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	$ 525.0
Union Electric Company
Loss Contingencies [Line Items]
Percentage of Rate Base Related to Carbon Dioxide Energy Centers		34.00%
Number of Energy Center Scrubbers | scrubber	2
Manufactured Gas Plant
Loss Contingencies [Line Items]
Accrual for environmental loss contingencies	$ 193.0
Manufactured Gas Plant | Ameren Illinois Company
Loss Contingencies [Line Items]
Number of remediation sites | site	44
Accrual for environmental loss contingencies	$ 193.0
Manufactured Gas Plant | Ameren Illinois Company | Minimum
Loss Contingencies [Line Items]
Estimate of possible loss	193.0
Manufactured Gas Plant | Ameren Illinois Company | Maximum
Loss Contingencies [Line Items]
Estimate of possible loss	258.0
Sauget Area Two | Union Electric Company
Loss Contingencies [Line Items]
Accrual for environmental loss contingencies	1.0
Sauget Area Two | Union Electric Company | Minimum
Loss Contingencies [Line Items]
Estimate of possible loss	1.0
Sauget Area Two | Union Electric Company | Maximum
Loss Contingencies [Line Items]
Estimate of possible loss	$ 2.5

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Callaway Energy Center (Narrative) (Detail) - Nuclear Plant $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) mill
Nuclear Waste Matters [Line Items]
Number of mills charged for NWF fee | mill	1
Annual decommissioning costs included in costs of service | $	$ 7

XML

Callaway Energy Center (Insurance Disclosure) (Detail) € in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)		Mar. 31, 2017 EUR (€)
Nuclear Waste Matters [Line Items]
Number of weeks of coverage after the first eight weeks of an outage	1 year		1 year
Threshold for which a retrospective assessment for a covered loss is necessary	$ 450,000,000
Annual payment in the event of an incident at any licensed commercial reactor	19,000,000
Amount of weekly indemnity coverage commencing eight weeks after power outage	4,500,000
Amount of additional weekly indemnity coverage commencing after initial indemnity coverage	$ 3,600,000
Inflationary adjustment prescribed by most recent Price-Anderson Act renewal, in years	5 years		5 years
Aggregate nuclear power industry insurance policy limit for losses from terrorist attacks within twelve month period	$ 3,200,000,000		€ 600
Number Of Additional Weeks After Initial Indemnity Coverage For Power Outage	1 year 4 months 10 days		1 year 4 months 10 days
Public Liability And Nuclear Worker Liability - American Nuclear Insurers
Nuclear Waste Matters [Line Items]
Maximum Coverages	$ 450,000,000
Maximum Assessments for Single Incidents	0
Public Liability And Nuclear Worker Liability - Pool Participation
Nuclear Waste Matters [Line Items]
Maximum Coverages	12,986,000,000	[1]
Maximum Assessments for Single Incidents	127,000,000	[2]
Property Damage - Nuclear Electric Insurance Ltd
Nuclear Waste Matters [Line Items]
Maximum Coverages	3,200,000,000	[3]
Maximum Assessments for Single Incidents	29,000,000	[4]
Replacement Power - Nuclear Electric Insurance Ltd
Nuclear Waste Matters [Line Items]
Maximum Coverages	490,000,000	[5]
Maximum Assessments for Single Incidents	7,000,000	[4]
Amount of weekly indemnity coverage thereafter not exceeding policy limit	490,000,000
Sub-limit of for non-nuclear events	328,000,000
Property Damage European Mutual Association for Nuclear Insurance
Nuclear Waste Matters [Line Items]
Maximum Coverages	490,000,000
Radiation Event
Nuclear Waste Matters [Line Items]
Maximum Coverages	2,700,000,000
Non-radiation event
Nuclear Waste Matters [Line Items]
Maximum Coverages	2,300,000,000
Aggregate nuclear power industry insurance policy limit for losses from terrorist attacks within twelve month period	1,800,000,000
Public Liability
Nuclear Waste Matters [Line Items]
Maximum Coverages	13,436,000,000	[6]
Maximum Assessments for Single Incidents	$ 127,000,000

[1] Provided through mandatory participation in an industrywide retrospective premium assessment program.

[2] Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $450 million in the event of an incident at any licensed United States commercial reactor, payable at $19 million per year.

[3] NEIL provides $2.7 billion in property damage, stabilization, decontamination, and premature decommissioning insurance for radiation events and $2.3 billion in property damage for nonradiation events. EMANI provides $490 million for both radiation and nonradiation events.

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

[5] 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 limited to $328 million.

[6] Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.

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Retirement Benefits (Components Of Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost		$ 23	$ 20
Interest cost		45	47
Expected return on plan assets		(66)	(63)
Prior service cost (benefit)		0	0
Actuarial loss		14	9
Net periodic benefit cost	[1],[2]	16	13
Other Postretirement Benefit Plan, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost		5	5
Interest cost		12	12
Expected return on plan assets		(19)	(18)
Prior service cost (benefit)		(1)	(1)
Actuarial loss		(2)	(3)
Net periodic benefit cost	[1],[2]	(5)	(5)
Union Electric Company | Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost		6	8
Union Electric Company | Other Postretirement Benefit Plan, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost		(1)	(1)
Ameren Illinois Company | Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost		10	5
Ameren Illinois Company | Other Postretirement Benefit Plan, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost		$ (4)	$ (4)

[1] (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

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

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Retirement Benefits (Summary Of Benefit Plan Costs Incurred) (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	[1],[2]	$ 16	$ 13
Pension Plan | Union Electric Company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost		6	8
Pension Plan | Ameren Illinois Company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost		10	5
Other Postretirement Benefit Plan, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	[1],[2]	(5)	(5)
Other Postretirement Benefit Plan, Defined Benefit | Union Electric Company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost		(1)	(1)
Other Postretirement Benefit Plan, Defined Benefit | Ameren Illinois Company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost		$ (4)	$ (4)

[1] (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

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

XML

Segment Information (Schedule Of Segment Reporting Information By Segment) (Detail) $ in Millions		3 Months Ended
		Mar. 31, 2017 USD ($) segment	Mar. 31, 2016 USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments | segment		4
External revenues		$ 1,514	$ 1,434
Net Income Attributable to Ameren Common Shareholders		102	105
Capital expenditures		$ 504	496
Union Electric Company
Segment Reporting Information [Line Items]
Number of Reportable Segments | segment		1
Consolidated
Segment Reporting Information [Line Items]
External revenues		$ 1,514	1,434
Intersegment revenues		0	0
Net Income Attributable to Ameren Common Shareholders		102	105
Capital expenditures		$ 504	496
Ameren Illinois Company
Segment Reporting Information [Line Items]
Number of Reportable Segments | segment		3
Ameren Illinois Company
Segment Reporting Information [Line Items]
External revenues		$ 703	677
Intersegment revenues		0	0
Net Income Available to Common Shareholder		79	59
Capital expenditures		227	211
Intersegment Eliminations
Segment Reporting Information [Line Items]
External revenues		0	0
Intersegment revenues		(25)	(27)
Net Income Available to Common Shareholder		0	0
Capital expenditures		(1)	0
Intersegment Eliminations | Ameren Illinois Company
Segment Reporting Information [Line Items]
External revenues		0	0
Intersegment revenues		(6)	(11)
Net Income Available to Common Shareholder		0	0
Capital expenditures		0	0
Operating Segments [Member] | Union Electric Company
Segment Reporting Information [Line Items]
External revenues		772	726
Intersegment revenues		18	15
Net Income Available to Common Shareholder		5	14
Capital expenditures		196	178
Operating Segments [Member] | Ameren Illinois Electric Distribution [Member]
Segment Reporting Information [Line Items]
External revenues		384	351
Intersegment revenues		1	1
Net Income Available to Common Shareholder		30	11
Capital expenditures		120	117
Operating Segments [Member] | Ameren Illinois Gas [Member]
Segment Reporting Information [Line Items]
External revenues		264	285
Intersegment revenues		0	0
Net Income Available to Common Shareholder		33	35
Capital expenditures		51	35
Operating Segments [Member] | Ameren Transmission [Member]
Segment Reporting Information [Line Items]
External revenues		96	72
Intersegment revenues	[1]	6	11
Net Income Available to Common Shareholder		34	27
Capital expenditures		134	164
Operating Segments [Member] | Other
Segment Reporting Information [Line Items]
External revenues		(2)	0
Intersegment revenues		0	0
Net Income Available to Common Shareholder		0	18
Capital expenditures	[2]	4	2
Operating Segments [Member] | Ameren Illinois Company | Ameren Illinois Electric Distribution [Member]
Segment Reporting Information [Line Items]
External revenues		385	352
Intersegment revenues		0	0
Net Income Available to Common Shareholder		30	11
Capital expenditures		120	117
Operating Segments [Member] | Ameren Illinois Company | Ameren Illinois Gas [Member]
Segment Reporting Information [Line Items]
External revenues		264	285
Intersegment revenues		0	0
Net Income Available to Common Shareholder		33	35
Capital expenditures		51	35
Operating Segments [Member] | Ameren Illinois Company | Ameren Illinois Transmission [Member]
Segment Reporting Information [Line Items]
External revenues		54	40
Intersegment revenues	[3]	6	11
Net Income Available to Common Shareholder		16	13
Capital expenditures		$ 56	$ 59

[1] (a)Ameren Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above.

[2] (b)Includes the elimination of intercompany transfers.

[3] (a)Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above.