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 June 30, 2018

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 July 31, 2018, was as follows:

Ameren Corporation	Common stock, $0.01 par value per share – 244,039,980
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 and Comprehensive Income	3
	Consolidated Balance Sheet	4
	Consolidated Statement of Cash Flows	5
	Union Electric Company (d/b/a Ameren Missouri)	6
	Statement of Income	6
	Balance Sheet	7
	Statement of Cash Flows	8
	Ameren Illinois Company (d/b/a Ameren Illinois)	9
	Statement of Income	9
	Balance Sheet	10
	Statement of Cash Flows	11
	Note 1. Summary of Significant Accounting Policies	12
	Note 2. Rate and Regulatory Matters	17
	Note 3. Short-term Debt and Liquidity	20
	Note 4. Long-term Debt and Equity Financings	21
	Note 5. Other Income, Net	22
	Note 6. Derivative Financial Instruments	22
	Note 7. Fair Value Measurements	24
	Note 8. Related-party Transactions	30
	Note 9. Commitments and Contingencies	31
	Note 10. Callaway Energy Center	35
	Note 11. Retirement Benefits	36
	Note 12. Segment Information	37
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	66
Item 4.	Controls and Procedures	67
PART II Other Information
Item 1.	Legal Proceedings	67
Item 1A.	Risk Factors	68
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	68
Item 6.	Exhibits	69
Signatures		70

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.

2017 IRP – Integrated Resource Plan, a 20-year nonbinding plan Ameren Missouri filed with the MoPSC in September 2017, that includes Ameren Missouri’s preferred approach for meeting customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliability.

CCR Rule– Coal Combustion Residuals Rule, a rule promulgated by the EPA that established regulations for the disposal of CCR in landfills and surface impoundments.

Form 10-K – The combined Annual Report on Form 10-K for the year ended December 31, 2017, filed by the Ameren Companies with the SEC.

Missouri Senate Bill 564 – A Missouri law that resulted in certain changes to Missouri utility laws that affect the regulation of Ameren Missouri’s electric service business. These changes include a reduction of customer rates to pass through the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA and, at each electric utility's election, the use of PISA, among other things.

PISA – Plant-in-service accounting, an election under Missouri Senate Bill 564 that permits electric utilities to defer and recover 85% of the depreciation expense and return on rate base on certain property, plant, and equipment placed in-service after August 28, 2018.

RESRAM – Renewable energy standard rate adjustment mechanism, a cost recovery mechanism, which is allowed under state law, that would allow Ameren Missouri to recover the cost of compliance with Missouri's renewable energy standard from customers and earn a return on those investments by adjusting customer rates on an annual basis without a traditional regulatory rate review.

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 the effects of the TCJA and 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 Missouri’s requested certificate of convenience and necessity for a wind generation facility and proposed RESRAM filed with the MoPSC in June 2018, Ameren Missouri’s proposed customer energy-efficiency plan under the MEEIA filed with the MoPSC in June 2018, Ameren Illinois’ natural gas regulatory rate review filed with the ICC in January 2018, Ameren Illinois’ April 2018 annual electric distribution formula rate update filing, and future regulatory, judicial, or legislative actions that change regulatory recovery mechanisms;

• the effect of Ameren Illinois’ participation in performance-based formula ratemaking frameworks under the IEIMA and the FEJA, 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 effect of the implementation of Missouri Senate Bill 564 on Ameren Missouri, including Ameren Missouri’s expected election to use PISA and the resulting customer rates caps;

• 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, amendments or technical corrections to the TCJA, 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 programs, including Ameren Missouri’s proposed customer energy-efficiency plan filed with the MoPSC in June 2018;

1

• Ameren Illinois’ ability to achieve the FEJA electric customer 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 and to recover these costs in a timely manner in our attempt to earn our allowed returns on equity;

• 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 emission credits, renewable energy credits, and natural gas for distribution; and the level and volatility of future market prices for such commodities and credits, including our ability to recover the costs for such commodities and credits and our customers' tolerance for any related price 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 energy center’s only NRC-licensed supplier of such assemblies;

• 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, including as a result of the implementation of the TCJA, 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;

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

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

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

• the effects of our increasing investment in electric transmission projects, our ability to obtain all necessary project approvals, 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 and the related proposed repeal and replacement of the Clean Power Plan, 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 negative opinions of us or our utility services that our customers, legislators, or regulators may have or develop, which could result from a variety of factors, including failures in system reliability, failure to implement our investment plans or to protect sensitive customer information, increases in rates, or negative media coverage;

• the impact of complying with renewable energy portfolio requirements in Missouri and Illinois and with the zero emission standard in Illinois;

• the effects of planned investment in renewable generation projects at Ameren Missouri, the ability to obtain all necessary project approvals, and the implementation of a proposed RESRAM;

• labor disputes, work force reductions, future wage and employee benefits costs, including changes in discount rates, mortality tables, returns on benefit plan assets, and other assumptions;

• 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 cyberattacks, which could, among other things, 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, employee, financial, and operating system 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 AND COMPREHENSIVE INCOME

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017		2018			2017
Operating Revenues:
Electric	$	1,396		$	1,382	$	2,619		$	2,589
Natural gas	167			155		529			463
Total operating revenues	1,563			1,537		3,148			3,052
Operating Expenses:
Fuel	186			189		374			395
Purchased power	142			150		305			330
Natural gas purchased for resale	51			41		222			171
Other operations and maintenance	439			431		870			849
Depreciation and amortization	238			222		472			443
Taxes other than income taxes	122			117		247			235
Total operating expenses	1,178			1,150		2,490			2,423
Operating Income	385			387		658			629
Other Income, Net	29			20		52			38
Interest Charges	100			99		201			198
Income Before Income Taxes	314			308		509			469
Income Taxes	74			114		116			171
Net Income	240			194		393			298
Less: Net Income Attributable to Noncontrolling Interests	1			1		3			3
Net Income Attributable to Ameren Common Shareholders	$	239		$	193	$	390		$	295
Net Income	$	240		$	194	$	393		$	298
Other Comprehensive Income (Loss), Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes of $-, $1, $-, and $1, respectively	(2		)	2		(1		)	2
Comprehensive Income	238			196		392			300
Less: Comprehensive Income Attributable to Noncontrolling Interests	1			1		3			3
Comprehensive Income Attributable to Ameren Common Shareholders	$	237		$	195	$	389		$	297
Earnings per Common Share – Basic	$	0.98		$	0.79	$	1.60		$	1.21
Earnings per Common Share – Diluted	$	0.97		$	0.79	$	1.59		$	1.21
Dividends per Common Share	$	0.4575		$	0.440	$	0.915		$	0.880
Weighted-average Common Shares Outstanding – Basic	243.7			242.6		243.3			242.6
Weighted-average Common Shares Outstanding – Diluted	245.8			243.5		245.1			243.7

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

3

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

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

	June 30, 2018			December 31, 2017
ASSETS
Current Assets:
Cash and cash equivalents	$	29		$	10
Accounts receivable – trade (less allowance for doubtful accounts of $25 and $19, respectively)	560			445
Unbilled revenue	371			323
Miscellaneous accounts receivable	74			70
Inventories	475			522
Current regulatory assets	104			144
Other current assets	72			98
Total current assets	1,685			1,612
Property, Plant, and Equipment, Net	21,998			21,466
Investments and Other Assets:
Nuclear decommissioning trust fund	714			704
Goodwill	411			411
Regulatory assets	1,205			1,230
Other assets	626			522
Total investments and other assets	2,956			2,867
TOTAL ASSETS	$	26,639		$	25,945
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	847		$	841
Short-term debt	506			484
Accounts and wages payable	565			902
Taxes accrued	139			52
Interest accrued	109			99
Customer deposits	114			108
Current regulatory liabilities	133			128
Other current liabilities	298			326
Total current liabilities	2,711			2,940
Long-term Debt, Net	7,613			7,094
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	2,584			2,506
Accumulated deferred investment tax credits	46			49
Regulatory liabilities	4,540			4,387
Asset retirement obligations	641			638
Pension and other postretirement benefits	545			545
Other deferred credits and liabilities	431			460
Total deferred credits and other liabilities	8,787			8,585
Commitments and Contingencies (Notes 2, 9, and 10)
Ameren Corporation Shareholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 244.0 and 242.6, respectively	2			2
Other paid-in capital, principally premium on common stock	5,576			5,540
Retained earnings	1,827			1,660
Accumulated other comprehensive loss	(19		)	(18		)
Total Ameren Corporation shareholders’ equity	7,386			7,184
Noncontrolling Interests	142			142
Total equity	7,528			7,326
TOTAL LIABILITIES AND EQUITY	$	26,639		$	25,945

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

4

AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Six Months Ended June 30,
	2018			2017
Cash Flows From Operating Activities:
Net income	$	393		$	298
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	463			433
Amortization of nuclear fuel	48			48
Amortization of debt issuance costs and premium/discounts	11			11
Deferred income taxes and investment tax credits, net	81			175
Allowance for equity funds used during construction	(14		)	(10		)
Stock-based compensation costs	10			8
Other	11			(5		)
Changes in assets and liabilities:
Receivables	(170		)	(54		)
Inventories	46			14
Accounts and wages payable	(209		)	(183		)
Taxes accrued	105			83
Regulatory assets and liabilities	83			(4		)
Assets, other	8			22
Liabilities, other	(50		)	21
Pension and other postretirement benefits	4			6
Net cash provided by operating activities	820			863
Cash Flows From Investing Activities:
Capital expenditures	(1,112		)	(998		)
Nuclear fuel expenditures	(16		)	(50		)
Purchases of securities – nuclear decommissioning trust fund	(129		)	(161		)
Sales and maturities of securities – nuclear decommissioning trust fund	122			152
Other	6			(2		)
Net cash used in investing activities	(1,129		)	(1,059		)
Cash Flows From Financing Activities:
Dividends on common stock	(223		)	(214		)
Dividends paid to noncontrolling interest holders	(3		)	(3		)
Short-term debt, net	21			334
Maturities of long-term debt	(323		)	(425		)
Issuances of long-term debt	853			549
Issuances of common stock	40			—
Repurchases of common stock for stock-based compensation	—			(24		)
Employee payroll taxes related to stock-based compensation	(19		)	(15		)
Debt issuance costs	(9		)	(4		)
Other	—			(1		)
Net cash provided by financing activities	337			197
Net change in cash, cash equivalents, and restricted cash	28			1
Cash, cash equivalents, and restricted cash at beginning of year	68			52
Cash, cash equivalents, and restricted cash at end of period	$	96		$	53
Noncash financing activity – Issuance of common stock for stock-based compensation	$	35		$	—

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

5

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

STATEMENT OF INCOME

(Unaudited) (In millions)

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Operating Revenues:
Electric	$	930	$	912	$	1,671	$	1,659
Natural gas	25		22		76		66
Total operating revenues	955		934		1,747		1,725
Operating Expenses:
Fuel	186		189		374		395
Purchased power	40		69		82		160
Natural gas purchased for resale	8		5		32		25
Other operations and maintenance	241		224		473		443
Depreciation and amortization	138		132		274		265
Taxes other than income taxes	84		85		164		160
Total operating expenses	697		704		1,399		1,448
Operating Income	258		230		348		277
Other Income, Net	16		16		29		32
Interest Charges	51		53		102		107
Income Before Income Taxes	223		193		275		202
Income Taxes	54		72		67		75
Net Income	169		121		208		127
Preferred Stock Dividends	1		1		2		2
Net Income Available to Common Shareholder	$	168	$	120	$	206	$	125

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

6

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

BALANCE SHEET

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

	June 30, 2018		December 31, 2017
ASSETS
Current Assets:
Cash and cash equivalents	$	17	$	—
Advances to money pool	66		—
Accounts receivable – trade (less allowance for doubtful accounts of $9 and $7, respectively)	285		200
Accounts receivable – affiliates	23		11
Unbilled revenue	256		165
Miscellaneous accounts receivable	55		35
Inventories	380		388
Current regulatory assets	48		56
Other current assets	42		50
Total current assets	1,172		905
Property, Plant, and Equipment, Net	11,835		11,751
Investments and Other Assets:
Nuclear decommissioning trust fund	714		704
Regulatory assets	367		395
Other assets	304		288
Total investments and other assets	1,385		1,387
TOTAL ASSETS	$	14,392	$	14,043
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	534	$	384
Short-term debt	—		39
Accounts and wages payable	226		475
Accounts payable – affiliates	125		60
Taxes accrued	110		30
Interest accrued	69		54
Current regulatory liabilities	50		19
Other current liabilities	107		103
Total current liabilities	1,221		1,164
Long-term Debt, Net	3,668		3,577
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,614		1,650
Accumulated deferred investment tax credits	45		48
Regulatory liabilities	2,754		2,664
Asset retirement obligations	637		634
Pension and other postretirement benefits	209		213
Other deferred credits and liabilities	7		12
Total deferred credits and other liabilities	5,266		5,221
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	1,858		1,858
Preferred stock	80		80
Retained earnings	1,788		1,632
Total shareholders’ equity	4,237		4,081
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	14,392	$	14,043

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)

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	Six Months Ended June 30,
	2018			2017
Cash Flows From Operating Activities:
Net income	$	208		$	127
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	265			255
Amortization of nuclear fuel	48			48
Amortization of debt issuance costs and premium/discounts	3			3
Deferred income taxes and investment tax credits, net	(24		)	13
Allowance for equity funds used during construction	(11		)	(9		)
Other	10			3
Changes in assets and liabilities:
Receivables	(205		)	(124		)
Inventories	8			(7		)
Accounts and wages payable	(160		)	(169		)
Taxes accrued	152			153
Regulatory assets and liabilities	106			57
Assets, other	(2		)	19
Liabilities, other	11			24
Pension and other postretirement benefits	3			3
Net cash provided by operating activities	412			396
Cash Flows From Investing Activities:
Capital expenditures	(454		)	(355		)
Nuclear fuel expenditures	(16		)	(50		)
Purchases of securities – nuclear decommissioning trust fund	(129		)	(161		)
Sales and maturities of securities – nuclear decommissioning trust fund	122			152
Money pool advances, net	(66		)	161
Net cash used in investing activities	(543		)	(253		)
Cash Flows From Financing Activities:
Dividends on common stock	(50		)	(172		)
Dividends on preferred stock	(2		)	(2		)
Short-term debt, net	(39		)	60
Maturities of long-term debt	(179		)	(425		)
Issuances of long-term debt	423			399
Debt issuance costs	(4		)	(3		)
Net cash provided by (used in) financing activities	149			(143		)
Net change in cash, cash equivalents, and restricted cash	18			—
Cash, cash equivalents, and restricted cash at beginning of year	7			5
Cash, cash equivalents, and restricted cash at end of period	$	25		$	5

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

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

STATEMENT OF INCOME

(Unaudited) (In millions)

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Operating Revenues:
Electric	$	436	$	442	$	885	$	881
Natural gas	142		134		453		398
Total operating revenues	578		576		1,338		1,279
Operating Expenses:
Purchased power	105		87		229		188
Natural gas purchased for resale	43		36		190		146
Other operations and maintenance	196		212		395		412
Depreciation and amortization	94		85		184		168
Taxes other than income taxes	35		28		76		68
Total operating expenses	473		448		1,074		982
Operating Income	105		128		264		297
Other Income, Net	13		3		19		3
Interest Charges	37		36		74		73
Income Before Income Taxes	81		95		209		227
Income Taxes	18		37		50		89
Net Income	63		58		159		138
Preferred Stock Dividends	1		1		2		2
Net Income Available to Common Shareholder	$	62	$	57	$	157	$	136

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

9

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

BALANCE SHEET

(Unaudited) (In millions)

	June 30, 2018		December 31, 2017
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	—
Accounts receivable – trade (less allowance for doubtful accounts of $16 and $12, respectively)	251		234
Accounts receivable – affiliates	21		9
Unbilled revenue	115		158
Miscellaneous accounts receivable	29		35
Inventories	95		134
Current regulatory assets	55		87
Other current assets	10		15
Total current assets	576		672
Property, Plant, and Equipment, Net	8,716		8,293
Investments and Other Assets:
Goodwill	411		411
Regulatory assets	822		822
Other assets	246		147
Total investments and other assets	1,479		1,380
TOTAL ASSETS	$	10,771	$	10,345
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	313	$	457
Short-term debt	—		62
Borrowings from money pool	31		—
Accounts and wages payable	291		337
Accounts payable – affiliates	44		70
Taxes accrued	15		19
Interest accrued	30		33
Customer deposits	75		69
Current environmental remediation	43		42
Current regulatory liabilities	65		92
Other current liabilities	150		177
Total current liabilities	1,057		1,358
Long-term Debt, Net	2,800		2,373
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,045		1,021
Regulatory liabilities	1,689		1,629
Pension and other postretirement benefits	292		285
Environmental remediation	123		134
Other deferred credits and liabilities	218		235
Total deferred credits and other liabilities	3,367		3,304
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	2,093		2,013
Preferred stock	62		62
Retained earnings	1,392		1,235
Total shareholders’ equity	3,547		3,310
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	10,771	$	10,345

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)

	Six Months Ended June 30,
	2018			2017
Cash Flows From Operating Activities:
Net income	$	159		$	138
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	184			168
Amortization of debt issuance costs and premium/discounts	7			7
Deferred income taxes and investment tax credits, net	13			116
Other	(3		)	—
Changes in assets and liabilities:
Receivables	23			70
Inventories	38			20
Accounts and wages payable	(35		)	(17		)
Taxes accrued	(23		)	(68		)
Regulatory assets and liabilities	(20		)	(54		)
Assets, other	4			3
Liabilities, other	(58		)	(10		)
Pension and other postretirement benefits	(2		)	2
Net cash provided by operating activities	287			375
Cash Flows From Investing Activities:
Capital expenditures	(602		)	(484		)
Other	3			4
Net cash used in investing activities	(599		)	(480		)
Cash Flows From Financing Activities:
Dividends on preferred stock	(2		)	(2		)
Short-term debt, net	(62		)	108
Money pool borrowings, net	31			—
Maturities of long-term debt	(144		)	—
Issuances of long-term debt	430			—
Debt issuance costs	(5		)	—
Capital contribution from parent	80			—
Other	—			(1		)
Net cash provided by financing activities	328			105
Net change in cash, cash equivalents, and restricted cash	16			—
Cash, cash equivalents, and restricted cash at beginning of year	41			28
Cash, cash equivalents, and restricted cash at end of period	$	57		$	28

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)

June 30, 2018

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company whose primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Ameren also has other subsidiaries that conduct other activities, such as providing shared services. Ameren evaluates competitive electric transmission investment opportunities 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 and Mark Twain projects, and placed the Spoon River project in service in February 2018.

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.

As of both June 30, 2018, and December 31, 2017, Ameren had unconsolidated variable interests as a limited partner in various equity method investments, totaling $17 million, included in “Other assets” on Ameren’s consolidated balance sheet. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly affect the activities of these variable interest entities. As of June 30, 2018, the maximum exposure to loss related to these variable interests is limited to the investment in these partnerships of $17 million plus associated outstanding funding commitments of $19 million.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and accompanying notes included in the Form 10-K.

Cash, Cash Equivalents, and Restricted Cash

Cash and cash equivalents include short-term, highly liquid investments purchased with an original maturity of three months or less. Cash and cash equivalents subject to legal or contractual restrictions and not readily available for use for general corporate purposes are classified as restricted cash.

In November 2016, the FASB issued authoritative guidance that requires, including on a retrospective basis, restricted cash to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Our adoption of this guidance, effective January 2018, did not result in material changes to previously reported cash flows from operating, investing, or financing activities.

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The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets and the statements of cash flows as of June 30, 2018 and 2017, and December 31, 2017 and 2016:

	June 30, 2018						December 31, 2017						June 30, 2017						December 31, 2016
	Ameren		Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois
Cash and cash equivalents(a)	$	29	$	17	$	—	$	10	$	—	$	—	$	10	$	—	$	—	$	9	$	—	$	—
Restricted cash included in “Other current assets”	12		4		6		21		5		6		19		4		5		20		4		6
Restricted cash included in “Other assets”	51		—		51		35		—		35		23		—		23		22		—		22
Restricted cash included in “Nuclear decommissioning trust fund”	4		4		(b)		2		2		(b)		1		1		(b)		1		1		(b)
Total cash, cash equivalents, and restricted cash(c)	$	96	$	25	$	57	$	68	$	7	$	41	$	53	$	5	$	28	$	52	$	5	$	28

(a) As presented on the balance sheet.

(b) Not applicable.

(c) As presented on the statement of cash flows.

Restricted cash included in Ameren’s other current assets primarily represents participant funds from Ameren (parent)’s DRPlus and funds held by an irrevocable Voluntary Employee Beneficiary Association trust, which provides health care benefits for active employees. Restricted cash included in Ameren Missouri’s and Ameren Illinois’ other current assets primarily represents funds held by the trust.

Restricted cash included in Ameren’s and Ameren Illinois’ other assets primarily represents amounts in a trust fund restricted for the use of funding certain asbestos-related claims and amounts collected under a cost recovery rider that are restricted for use in the procurement of renewable energy credits.

Supplemental Cash Flow Information

The following table provides noncash investing activity excluded from the statements of cash flows for the six months ended June 30, 2018 and 2017:

	June 30, 2018						June 30, 2017
	Ameren(a)		Ameren Missouri		Ameren Illinois		Ameren(a)		Ameren Missouri		Ameren Illinois
Accrued capital expenditures	$	233	$	80	$	147	$	175	$	61	$	79
Net realized and unrealized gain – nuclear decommissioning trust fund	1		1		(b)		36		36		(b)

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

(b) Not applicable.

Accounts Receivable

"Accounts receivable – trade" on Ameren's and Ameren Illinois' balance sheets include certain receivables purchased at a discount from alternative retail electric suppliers that elect to participate in the utility consolidated billing program. At June 30, 2018, and December 31, 2017, "Other current liabilities" on Ameren's and Ameren Illinois' balance sheets included payables for purchased receivables of $40 million and $31 million, respectively.

For the three and six months ended June 30, 2018 and 2017, the Ameren Companies recorded immaterial bad debt expense.

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Asset Retirement Obligations

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the six months ended June 30, 2018:

	Ameren Missouri				Ameren Illinois(a)		Ameren
Balance at December 31, 2017	$	640		(b)	$	4	$	644		(b)
Liabilities settled	(2		)		(c)		(2		)
Accretion(d)	14				(c)		14
Change in estimates(e)	(9		)		—		(9		)
Balance at June 30, 2018	$	643		(b)	$	4	$	647		(b)

(a) Included in “Other deferred credits and liabilities” on the balance sheet.

(b) Balance included $6 million in “Other current liabilities” on the balance sheet as of both December 31, 2017, and June 30, 2018, respectively.

(c) Less than $1 million.

(d) Accretion expense attributable to Ameren Missouri was recorded as a decrease to regulatory liabilities.

(e) Ameren Missouri changed its fair value estimate primarily due to a reduction in the cost estimate for closure of certain CCR storage facilities.

Company-owned Life Insurance

Ameren and Ameren Illinois have company-owned life insurance, which is recorded at the net cash surrender value. The net cash surrender value is the amount that can be realized under the insurance policies at the balance sheet date. As of June 30, 2018, the cash surrender value of company-owned life insurance at Ameren and Ameren Illinois was $249 million (December 31, 2017 – $265 million) and $117 million (December 31, 2017 – $129 million), respectively, while total borrowings against the policies were $107 million (December 31, 2017 – $120 million) at both Ameren and Ameren Illinois. Ameren and Ameren Illinois have the right to offset the borrowings against the cash surrender value of the policies and, consequently, present the net asset in “Other assets” on their respective balance sheets.

Stock-based Compensation

The following table summarizes Ameren's nonvested performance share unit and restricted stock unit activity for the six months ended June 30, 2018:

	Performance Share Units				Restricted Stock Units
	Share Units		Weighted-average Fair Value per Share Unit		Stock Units		Weighted-average Fair Value per Stock Unit
Nonvested at January 1, 2018(a)	895,489		$	52.28	—		$	—
Granted	306,252		62.88		184,351		57.60
Forfeitures	(54,213	)	49.72		(3,560	)	58.99
Undistributed vested units(b)	(145,169	)	53.50		(12,983	)	58.98
Vested and distributed	(176,043	)	52.88		—		—
Nonvested at June 30, 2018(c)	826,316		$	56.03	167,808		$	57.46

(a) Does not include 712,572 undistributed vested performance share units.

(b) Undistributed vested units are awards that vested due to attainment of retirement eligibility by certain employees, but have not yet been distributed. For undistributed vested performance share units, the number of shares issued for retirement-eligible employees will vary depending on actual performance over the three-year performance period.

(c) Does not include 476,361 undistributed vested performance share units and 12,983 undistributed vested restricted stock units.

Performance Share Units

A performance share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, certain specified market conditions have been met and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date. In the event of a participant’s death or retirement at age 55 or older with five or more years of service, awards vest on a pro rata basis over the three-year performance period. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals.

The fair value of each performance share unit granted in 2018 was determined to be $62.88, which was based on Ameren’s closing common share price of $58.99 at December 31, 2017, 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, 2018, 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

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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 1.98% and volatility of 15% to 23% for the peer group.

Restricted Stock Units

Restricted stock units vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if the individual remains employed with Ameren through the payment date of the awards. Generally, in the event of a participant’s death or retirement at age 55 or older with five or more years of service, awards vest on a pro rata basis. The payout date of the awards is approximately 38 months after the grant date. The fair value of each restricted stock unit is determined by Ameren’s closing common share price on the grant date.

Deferred Compensation

As of June 30, 2018, and December 31, 2017, “Other deferred credits and liabilities” on Ameren’s balance sheet included deferred compensation obligations of $85 million and $86 million, respectively, recorded at the present value of future benefits to be paid.

Operating Revenues

In the first quarter of 2018, we adopted authoritative accounting guidance related to revenue from contracts with customers using the full retrospective method, with no material changes to the amount or timing of revenue recognition. We record revenues from contracts with customers for various electric and natural gas services, which primarily consist of retail distribution, electric transmission, and off-system arrangements. When more than one performance obligation exists in a contract, the consideration under the contract is allocated to the performance obligations based on the relative standalone selling price.

Electric and natural gas retail distribution revenues are earned when the commodity is delivered to our customers. We accrue an estimate of electric and natural gas retail distribution revenues for service provided but unbilled at the end of each accounting period.

Electric transmission revenues are earned as electric transmission services are provided.

Off-system revenues are primarily comprised of MISO revenues and wholesale bilateral revenues. MISO revenues include the sale of electricity, capacity, and ancillary services. Wholesale bilateral revenues include the sale of electricity and capacity. MISO-related electricity and wholesale bilateral electricity revenues are earned as electricity is delivered. MISO-related capacity and ancillary service revenues and wholesale bilateral capacity revenues are earned as services are provided.

Retail distribution, electric transmission, and off-system revenues, including the underlying components described above, represent a series of goods or services that are substantially the same and have the same pattern of transfer over time to our customers. Revenues from contracts with customers is equal to the amounts billed and our estimate of electric and natural gas retail distribution services provided but unbilled at the end of each accounting period. Revenues are billed at least monthly, and payments are due less than one month after goods and/or services are provided. See Note 12 – Segment Information for disaggregated revenue information.

For certain regulatory recovery mechanisms that are alternative revenue programs, rather than revenues from contracts with customers, we 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 from the end of the year. Our alternative revenue programs include revenue requirement reconciliations, MEEIA, and VBA. These revenues are subsequently recognized as revenues from contracts with customers when billed, with an offset to alternative revenue program revenues.

The Ameren Companies elected to exclude disclosure related to the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied as of the end of the reporting period for contracts with an initial expected term of one year or less. As of June 30, 2018 and 2017, our remaining performance obligations were immaterial.

Excise Taxes

Ameren Missouri and Ameren Illinois collect from their customers excise taxes, including municipal and state excise taxes and gross receipts taxes, that are levied on the sale or distribution of natural gas and electricity. Excise taxes are recorded gross in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” on the statements of income. The following table presents the excise taxes recorded in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” for the three and six months ended June 30, 2018 and 2017:

15

	Three Months					Six Months
	2018		2017			2018		2017
Ameren Missouri	$	46	$	40		$	80	$	71
Ameren Illinois	28		23		(a)	63		57		(a)
Ameren	$	74	$	63	(a)	$	143	$	128	(a)

(a) Amounts have been adjusted from those previously reported to reflect additional excise taxes for the three and six months ended June 30, 2017, respectively.

Income Taxes

The following table presents a reconciliation of the federal statutory corporate income tax rate to the effective income tax rate for the three and six months ended June 30, 2018 and 2017:

	Ameren		Ameren Missouri			Ameren Illinois
Three Months	2018	2017	2018		2017	2018	2017
Federal statutory corporate income tax rate:	21%	35%	21%		35%	21%	35%
Increases (decreases) from:
Amortization of excess deferred taxes	(1)	—	—	(a)	—	(5)	—
Other depreciation differences	—	—	—		—	(1)	(1)
Amortization of deferred investment tax credit	—	—	(1)		(1)	—	—
State tax	5	4	4		3	8	5
Tax credits	(1)	—	—		—	—	—
Other permanent items	—	(1)	—		—	—	—
Effective income tax rate	24%	38%	24%		37%	23%	39%
Six Months
Federal statutory corporate income tax rate:	21%	35%	21%		35%	21%	35%
Increases (decreases) from:
Amortization of excess deferred taxes	(2)	—	—	(a)	—	(4)	—
Amortization of deferred investment tax credit	(1)	(1)	(1)		(1)	—	—
State tax	6	5	4		3	7	5
Other permanent items	(1)	(2)	—		—	—	(1)
Effective income tax rate	23%	37%	24%		37%	24%	39%

(a) Based on an order issued by the MoPSC in July 2018, Ameren Missouri began amortizing excess deferred taxes in August 2018. See Note 2 – Rate and Regulatory Matters for additional information.

In June 2018, legislation modifying Missouri tax law was enacted to decrease the state's corporate income tax rate from 6.25% to 4%, effective January 1, 2020. As a result, in the second quarter of 2018, Ameren’s and Ameren Missouri’s accumulated deferred tax balances were revalued, resulting in a net decrease to their accumulated deferred tax liability of $33 million, which was offset by a regulatory liability. Additionally, Ameren recorded an immaterial amount to income tax expense. As a result of its expected PISA election under Missouri Senate Bill 564, which would prohibit a change in electric base rates prior to April 2020, Ameren Missouri anticipates that the effect of this tax decrease will be reflected in customer rates upon completion of its next regulatory rate review. Ameren (parent) and nonregistrant subsidiaries do not expect this income tax decrease to have a material impact on net income prospectively.

Earnings Per Share

Basic earnings per share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of common shares outstanding during the period. Earnings per diluted share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of diluted common shares outstanding during the period. Earnings per diluted share reflects the dilution that would occur if certain stock-based performance share units were assumed to be settled. The number of performance share units assumed to be settled was 2.1 million and 1.8 million in the three and six months ended June 30, 2018, respectively, and 0.8 million and 1.1 million, respectively, in the year-ago periods. There were no potentially dilutive securities excluded from the earnings per diluted share calculations for the three and six months ended June 30, 2018 and 2017.

Accounting and Reporting Developments

In the first quarter of 2018, the Ameren Companies adopted authoritative accounting guidance on various topics. See the Operating Revenues section above for more information on our adoption of the guidance on revenue from contracts with customers. See Note 11 – Retirement Benefits for more information on our adoption of the guidance on the presentation of net periodic pension and postretirement benefit cost. See the Cash, Cash Equivalents, and Restricted Cash section above for more information on our adoption of the guidance on

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restricted cash. Our adoption of the guidance on the recognition and measurement of financial assets and financial liabilities did not have a material impact on our results of operations or financial position.

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, the measurement of credit losses on financial instruments, and the reclassification of certain tax effects from accumulated OCI.

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

Missouri Senate Bill 564

On June 1, 2018, Missouri Senate Bill 564 was enacted. The section of the law applicable to the TCJA became effective immediately; the remaining sections, including the ability to elect PISA, become effective August 28, 2018. The law resulted in certain changes to Missouri utility laws that affect the regulation of Ameren Missouri’s electric service business. These changes include the reduction of customer rates to pass through the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA and, at each electric utility's election, the use of PISA. Electric utilities that do not elect to use PISA will be eligible to request permission to implement revenue decoupling of residential and other non-demand metered customer classes. The law required the MoPSC to authorize a reduction in Ameren Missouri’s rates to pass through the effect of the TCJA within 90 days of the law’s effective date. In July 2018, the MoPSC authorized Ameren Missouri to reduce its annual revenue requirement by$167 millionand reflect that reduction in rates beginning August 1, 2018. The reduction included $74 million for the amortization of excess accumulated deferred income taxes. In addition, Ameren Missouri recorded a reduction to revenue and a corresponding regulatory liability of $47 million for the excess amounts collected in rates related to the TCJA from January 1, 2018, through June 30, 2018. An additional amount will be recorded for July 2018 revenues. The regulatory liability will be reflected in customer rates over a period of time to be determined by the MoPSC in the next regulatory rate review.

Upon Ameren Missouri’s expected PISA election, it would be permitted to defer and recover 85% of the depreciation expense and return on rate base on certain property, plant, and equipment placed in-service after August 28, 2018, and not included in base rates. Eligible PISA deferrals would exclude amounts related to new coal-fired, nuclear, and natural gas generating units and service to new customer premises. Upon approval in a regulatory rate review, PISA deferrals would be added to rate base prospectively and earn a return based on Ameren Missouri’s weighted-average cost of capital over a recovery period of 20 years. For electric utilities electing to use PISA, additional provisions apply, including limitations on customer rate increases. Ameren Missouri’s customer rate increases would be limited to a 2.85% compound annual growth rate in the average overall customer rate per kilowatthour, applied to electric rates effective April 1, 2017, less half of the 2018 savings from the TCJA that was passed on to customers. Upon election to use PISA, Ameren Missouri’s electric base rates would be frozen until April 1, 2020. Recoveries under the MEEIA, the FAC, and the RESRAM riders would not be frozen; however, except for costs recoverable under the MEEIA rider, Ameren Missouri would be unable to recover any amounts above the 2.85% cap from customers. If rate changes from the FAC or the RESRAM riders would cause rates to temporarily exceed the 2.85% cap, the overage would be deferred for future recovery in the next regulatory rate review; however, rates established in such regulatory rate review would be subject to the rate cap. Any deferred overages approved for recovery would be subject to deferral and recovered in a manner consistent with costs recovered under PISA. Both the rate cap and PISA election would be effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028. Ameren Missouri’s expected PISA election will support Ameren Missouri's ability to invest approximately $1 billion of incremental capital over the 2019 to 2023 period to strengthen and modernize Missouri's electric grid.

MoPSC Federal Income Tax Proceedings

In February 2018, the MoPSC initiated proceedings to investigate how the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA should be reflected in rates paid by customers of Missouri’s regulated utilities, including rates paid by electric and natural gas customers of Ameren Missouri. The proceeding for Ameren Missouri’s electric service business was dismissed after Missouri Senate Bill 564 was enacted on June 1, 2018, but the proceeding is still pending for Ameren Missouri’s natural gas distribution business. As of June 30, 2018, the potential reduction in natural gas customer rates is immaterial. The MoPSC is under no deadline to issue an order in the natural gas proceeding.

Wind Generation Facility and RESRAM

In the second quarter of 2018, Ameren Missouri entered into an agreement with a subsidiary of Terra-Gen, LLC to acquire a 400-megawatt wind generation facility after construction. The facility is expected to be located in northeastern Missouri and to be completed in

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2020. The acquisition is subject to certain conditions, including the issuance of a certificate of convenience and necessity by the MoPSC, obtaining a MISO transmission interconnection agreement, and approval by the FERC. Ameren Missouri has filed for the certificate of convenience and necessity with the MoPSC. This facility would help Ameren Missouri to comply with the state renewable energy standard.In addition, Ameren Missouri requested the MoPSC to authorize a proposed RESRAM that would allow Ameren Missouri to adjust customer rates, including recovery of interest at a short-term borrowing rate, on an annual basis without a traditional regulatory rate review. The RESRAM is designed to mitigate the impacts of regulatory lag for investments in wind generation and other renewables by providing more timely recovery of costs and would provide Ameren Missouri a greater opportunity to earn its allowed return on investment. Ameren Missouri anticipates a decision by January 2019 related to the certificate of convenience and necessity and proposed RESRAM.

Renewable Choice Program

In June 2018, the MoPSC approved Ameren Missouri’s Renewable Choice Program, which allows large commercial and industrial customers and municipalities to receive up to 100 percent of their energy from renewable resources. The tariff-based program is designed to recover the costs of the election, net of changes in the market price of such energy. Based on customer contracts, the program enables Ameren Missouri to supply up to 400 megawatts of renewable wind energy generation, up to 200 megawatts of which it could own. As applicable, the addition of generation by Ameren Missouri would be subject to the issuance of a certificate of convenience and necessity by the MoPSC, obtaining transmission interconnection agreements with the MISO or other RTOs, and approval by the FERC. This generation would be incremental to the expected renewable generation included in the 2017 IRP. Without extension, the option to elect into the program will terminate in the third quarter of 2023.

MEEIA

In June 2018, Ameren Missouri filed a proposed customer energy-efficiency plan with the MoPSC under the MEEIA. This filing proposed a six-year plan, which includes a portfolio of customer energy-efficiency programs, along with a cost recovery mechanism. If the plan is approved, beginning in March 2019, Ameren Missouri intends to invest an average of $92 million per program year in the proposed customer energy-efficiency programs. Ameren Missouri requested continued use of a MEEIA rider, which allows Ameren Missouri to collect from or refund to customers any difference in the actual amounts incurred and the amounts collected from customers for the MEEIA program costs and its lost revenues. In addition, Ameren Missouri requested incentives to earn additional revenues by achieving certain customer energy-efficiency goals, increasing from $10 million to $24 million annually, for a total of $115 million over the six-year period if 100% of its annual customer energy-efficiency goals are achieved. A decision by the MoPSC in this proceeding is anticipated by the first quarter of 2019.

The MEEIA 2016 program provided Ameren Missouri with a performance incentive to earn additional revenues by achieving certain customer energy-efficiency goals, including $27 million if 100% of the goals were achieved during the three-year period beginning March 2016, with the potential to earn more if Ameren Missouri’s energy savings exceeded those goals. In September 2017, Ameren Missouri received an order from the MoPSC approving Ameren Missouri’s energy savings results for the first year of the MEEIA 2016 programs. As a result of this order and in accordance with revenue recognition guidance, Ameren Missouri recognized $5 million of revenues in the first quarter of 2018 relating to the MEEIA 2016 performance incentive.

In July 2018, the Missouri Supreme Court overturned a 2016 decision by the Missouri Court of Appeals, Western District, which had upheld a 2015 MoPSC order regarding the determination of a certain input used to calculate the MEEIA 2013 performance incentive, and remanded the matter to the MoPSC. The MoPSC is required to issue a revised order consistent with the Missouri Supreme Court’s ruling; however, there is no deadline to issue such order. Upon issuance of the order, Ameren Missouri expects to recognize an additional $9 million MEEIA 2013 performance incentive.

Illinois

Electric Distribution Service Rates

In April 2018, Ameren Illinois filed its annual electric distribution service formula rate update to establish the revenue requirement to be used for 2019 rates with the ICC. In July 2018, the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing, recommending an amount comparable to Ameren Illinois’ filing. Pending ICC approval, this update filing will result in a$72 millionincrease in Ameren Illinois’ electric distribution service rates beginning in January 2019.This update reflects an increase to the annual formula rate based on 2017 actual costs and expected net plant additions for 2018 and an increase to include the 2017 revenue requirement reconciliation adjustment. It also includes a decrease for the conclusion of the 2016 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2018, consistent with the ICC’s December 2017 annual update filing order. An ICC decision in this proceeding is expected by December 2018. As of June 30, 2018, Ameren Illinois had recorded a regulatory asset of $62 million to reflect the difference between Ameren Illinois’ estimate of its 2018 revenue requirement and the revenue requirement reflected in customer rates, including interest.

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Electric Customer Energy-Efficiency Investments

In June 2018, Ameren Illinois filed its annual electric customer energy-efficiency formula rate update to establish the revenue requirement to be used for 2019 rates with the ICC. Pending ICC approval, this update filing will result in 2019 rates for electric customer energy-efficiency investments of $34 million, which represents an increase of $20 million from the 2018 rates. An ICC decision regarding the revenue requirement to be used for customer rates in 2019 is expected by December 2018.

Income Tax Regulatory Mechanisms

In February 2018, the ICC granted Ameren Illinois’ request, filed in January 2018, to establish a rider to reduce Ameren Illinois’ electric distribution customer rates for the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA and the return of excess deferred taxes, net of the increase in state income taxes enacted in July 2017. Ameren Illinois' electric distribution customer rates were reduced as a result of the rider beginning in the first quarter of 2018. The estimated reduction of $50 million per year will continue through 2019, as base rates will reflect the current income tax rates starting in 2020.

In April 2018, the ICC approved a rider for the difference between revenues billed under natural gas rates established pursuant to Ameren Illinois’ most recent natural gas rate order, and the revenues that would have been billed had the state and federal tax rate changes discussed above been in effect. The rider required Ameren Illinois to record this regulatory liability beginning January 25, 2018. Ameren Illinois’ natural gas customer rates were reduced as a result of the rider beginning in May 2018, with an estimated reduction of up to $17 million, substantially over a one-year period.

2018 Natural Gas Delivery Service Regulatory Rate Review

In January 2018, Ameren Illinois filed a request with the ICC seeking approval to increase its annual rates for natural gas delivery service. In July 2018, Ameren Illinois and the ICC staff filed a stipulation and agreement with the ICC that, pending ICC approval, would result in an annual natural gas rate increase of $37 million, based on the terms of the agreement and subject to adjustments for updated rate case and other postretirement benefit expenses. This increase in annual rates includes a 9.87% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion. It also reflects the reduction in the federal corporate income tax rate as a result of the TCJA, as well as the increase in the Illinois corporate income tax rate that became effective in July 2017, which decreased the annual rates by approximately $17 million. In an attempt to reduce regulatory lag, Ameren Illinois used a 2019 future test year in this proceeding.

A decision by the ICC in this proceeding is required by December 2018, with new rates expected to be effective in January 2019. Ameren Illinois cannot predict the level of any delivery service rate changes the ICC may approve, nor whether any rate changes that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and to earn a reasonable return on investments when the rate changes go into effect.

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 2016, the FERC issued a final order in the November 2013 complaint case, which lowered the allowed base return on common equity to 10.32%, or a 10.82% total allowed return on common equity with the inclusion of a 50 basis point incentive adder for participation in an RTO, effective since September 2016. The 10.82% allowed return on common equity may be replaced prospectively after the FERC issues a final order in the February 2015 complaint case, discussed below.

Since 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. MISO transmission owners subsequently filed a motion to dismiss the February 2015 complaint, as discussed below. The February 2015 complaint case seeks a further reduction in the allowed base return on common equity for 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. If approved by the FERC, it 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 a 50 basis point incentive adder for participation in an RTO. It would also require customer refunds, with interest, for that 15-month period. A final FERC order would also establish the allowed return on common equity that will apply prospectively from the effective date of such order, replacing the current 10.82% total return on common equity. In the second quarter of 2017, the United States Court of Appeals for the District of Columbia Circuit 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

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the District of Columbia Circuit’s remand on the MISO FERC complaint cases at this time. As the FERC is under no deadline to issue a final order, the timing of the issuance of the final order in the February 2015 complaint case is uncertain.

In September 2017, MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed a motion to dismiss the February 2015 complaint case with the FERC. The MISO transmission owners maintain that the February 2015 complaint was predicated on the now superseded 12.38% allowed base return on common equity and is therefore inapplicable given the current 10.32% allowed base return on common equity. The MISO transmission owners further maintain that the current 10.32% allowed base return on common equity has not been proven to be unjust and unreasonable based on information provided, including the base return on common equity methodology ranges set forth in the February 2015 complaint case and in the initial decision issued by an administrative law judge in June 2016. Additionally, the MISO transmission owners maintain that the February 2015 complaint should be dismissed because the approach utilized in the case to assert that a return on common equity was unjust and unreasonable was insufficient. That same approach was rejected by the United States Court of Appeals for the District of Columbia Circuit, as discussed above. The FERC is under no deadline to issue an order on this motion.

As of June 30, 2018, Ameren and Ameren Illinois had recorded current regulatory liabilities of $43 million and $25 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.

FERC Federal Income Tax Proceeding and Formula Rate Change

In March 2018, the FERC granted a request filed in February 2018 by MISO transmission owners with forward-looking rate formulas, including Ameren Illinois and ATXI, to allow revisions to their 2018 electric transmission rates to reflect the effect of the reduction in federal income taxes enacted under the TCJA. Ameren Illinois and ATXI’s 2018 electric transmission rates have been reduced by $27 million and $23 million, respectively.

In May 2018, the FERC accepted Ameren Illinois and ATXI tariff filings to change the formula rate calculation. The change allows for the recovery or refund of both excess deferred income taxes resulting from tax law or rate changes and effect of permanent income tax differences and will be reflected in Ameren Illinois and ATXI’s electric transmission rates starting in January 2019.

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 affiliate 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 six months ended June 30, 2018, but were used to support commercial paper issuances and to issue letters of credit. Based on commercial paper outstanding, letters of credit issued under the Credit Agreements, and cash on hand, the aggregate credit capacity available under the Credit Agreements to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, at June 30, 2018, was $1.6 billion. The Ameren Companies were in compliance with the covenants in their Credit Agreements as of June 30, 2018. As of June 30, 2018, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the provisions of the Credit Agreements, were 54%, 48%, and 47% for Ameren, Ameren Missouri, and Ameren Illinois, respectively.

Commercial Paper

The following table presents commercial paper outstanding, net of issuance discounts, as of June 30, 2018, and December 31, 2017:

	2018		2017
Ameren (parent)	$	506	$	383
Ameren Missouri	—		39
Ameren Illinois	—		62
Ameren Consolidated	$	506	$	484

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The following table summarizes the borrowing activity and relevant interest rates under Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs for the six months ended June 30, 2018 and 2017:

	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated
2018
Average daily commercial paper outstanding at par value	$	397		$	123		$	174		$	693
Weighted-average interest rate	2.14		%	1.94		%	2.20		%	2.12		%
Peak commercial paper during period at par value(a)	$	506		$	481		$	442		$	1,295
Peak interest rate	2.45		%	2.42		%	2.55		%	2.55		%
2017
Average daily commercial paper outstanding at par value	$	736		$	6		$	66		$	808
Weighted-average interest rate	1.19		%	1.10		%	1.14		%	1.19		%
Peak commercial paper during period at par value(a)	$	841		$	60		$	163		$	948
Peak interest rate	1.50		%	1.41		%	1.50		%	1.50		%

(a) The timing of peak outstanding commercial paper issuances varies by company. Therefore, the sum of individual company peak amounts may 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 borrowings under the money pool for the three and six months ended June 30, 2018, was 2.17% and 2.04%, respectively (2017 – 1.27% and 1.14%, respectively). See Note 8 – Related-party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three and six months ended June 30, 2018 and 2017.

NOTE 4 – LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

For the three and six months ended June 30, 2018, Ameren issued a total of 0.4 million and 0.7 million shares, respectively, of common stock under its DRPlus and 401(k) plan and received proceeds of $23 million and $40 million, respectively. In addition, in the first quarter of 2018, Ameren issued 0.7 million shares of common stock valued at $35 million upon the vesting of stock-based compensation. Ameren did not issue any common stock during the first six months of 2017.

Ameren Missouri

In April 2018, Ameren Missouri issued $425 million of 4.00% first mortgage bonds due April 2048, with interest payable semiannually on April 1 and October 1 of each year, beginning October 1, 2018. Ameren Missouri received proceeds of $419 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Missouri incurred in connection with the repayment of $179 million of its 6.00% senior secured notes that matured April 1, 2018.

Ameren Illinois

In May 2018, Ameren Illinois issued $430 million of 3.80% first mortgage bonds due May 2028, with interest payable semiannually on May 15 and November 15 of each year, beginning November 15, 2018. Ameren Illinois received proceeds of $427 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Illinois incurred in connection with the repayment of $144 million of its 6.25% senior secured notes that matured April 1, 2018.

Indenture Provisions and Other Covenants

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. At June 30, 2018, the Ameren Companies were in compliance with the provisions and covenants contained in their indentures and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement.

Off-balance-sheet Arrangements

At June 30, 2018, none of the Ameren Companies had any significant 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.

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NOTE 5 – OTHER INCOME, NET

The following table presents the components of “Other Income, Net” in the Ameren Companies’ statements of income for the three and six months ended June 30, 2018 and 2017:

	Three Months							Six Months
	2018				2017			2018				2017
Ameren:(a)
Other Income, Net
Allowance for equity funds used during construction	$	9			$	4		$	14			$	10
Interest income on industrial development revenue bonds	7				6			13				13
Other interest income	2				3			4				5
Non-service cost components of net periodic benefit income	19			(b)	10			35			(b)	22
Other income	2				2			3				2
Donations	(6		)		(2		)	(11		)		(7		)
Other expense	(4		)		(3		)	(6		)		(7		)
Total Other Income, Net	$	29			$	20		$	52			$	38
Ameren Missouri:
Other Income, Net
Allowance for equity funds used during construction	$	7			$	4		$	11			$	9
Interest income on industrial development revenue bonds	7				6			13				13
Other interest income	1				1			1				1
Non-service cost components of net periodic benefit income	4			(b)	6			9			(b)	12
Other income	—				1			1				1
Donations	(2		)		(2		)	(3		)		(2		)
Other expense	(1		)		—			(3		)		(2		)
Total Other Income, Net	$	16			$	16		$	29			$	32
Ameren Illinois:
Other Income, Net
Allowance for equity funds used during construction	$	2			$	—		$	3			$	1
Interest income	1				2			3				4
Non-service cost components of net periodic benefit income	10				1			17				4
Other income	2				2			2				2
Donations	(1		)		(1		)	(5		)		(5		)
Other expense	(1		)		(1		)	(1		)		(3		)
Total Other Income, Net	$	13			$	3		$	19			$	3

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

(b) For the three and six months ended June 30, 2018, the non-service cost components of net periodic benefit income were partially offset by a $4 million and $8 million deferral due to a regulatory tracking mechanism for the difference between the level of such costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates.

NOTE 6 – DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives to manage the risk of changes in market prices for natural gas and power, 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 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 June 30, 2018, and December 31, 2017. As of June 30, 2018, these contracts extended through October 2021, March 2023, and May 2032 for fuel oils, natural gas, and power, respectively.

	Quantity (in millions, except as indicated)
	2018			2017
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)(a)	40	(b)	40	28	(b)	28
Natural gas (in mmbtu)	23	149	172	24	139	163
Power (in megawatthours)	2	8	10	3	9	12

(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 June 30, 2018, and December 31, 2017, 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 June 30, 2018, and December 31, 2017:

	Balance Sheet Location	Ameren Missouri		Ameren Illinois		Ameren
2018
Fuel oils	Other current assets	$	8	$	—	$	8
	Other assets	5		—		5
Natural gas	Other current assets	—		1		1
	Other assets	—		1		1
Power	Other current assets	7		—		7
	Total assets (a)	$	20	$	2	$	22
Fuel oils	Other deferred credits and liabilities	$	1	$	—	$	1
Natural gas	Other current liabilities	4		12		16
	Other deferred credits and liabilities	3		13		16
Power	Other current liabilities	2		13		15
	Other deferred credits and liabilities	—		177		177
	Total liabilities (b)	$	10	$	215	$	225
2017
Fuel oils	Other current assets	$	5	$	—	$	5
	Other assets	2		—		2
Natural gas	Other assets	1		—		1
Power	Other current assets	9		—		9
	Total assets (a)	$	17	$	—	$	17
Natural gas	Other current liabilities	$	5	$	12	$	17
	Other deferred credits and liabilities	3		10		13
Power	Other current liabilities	1		13		14
	Other deferred credits and liabilities	—		182		182
	Total liabilities (b)	$	9	$	217	$	226

(a) The cumulative amount of pretax net gains on all derivative instruments is deferred as a regulatory liability.

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

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Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges; 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 June 30, 2018, and December 31, 2017.

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 June 30, 2018, if all counterparties were to fail 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 June 30, 2018, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that counterparties could require. The additional collateral required is the net liability position allowed under the master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered on June 30, 2018, 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)
Ameren Missouri	$	63	$	4	$	52
Ameren Illinois	52		—		47
Ameren	$	115	$	4	$	99

(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.

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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). We have also 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 three and six months ended June 30, 2018 or 2017. At June 30, 2018, and December 31, 2017, the counterparty default risk valuation adjustment related to derivative contracts was immaterial for Ameren, Ameren Missouri, and Ameren Illinois.

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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 June 30, 2018:

		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	$	8	$	—	$	5	$	13
	Natural gas	—		1		1		2
	Power	—		—		7		7
	Total derivative assets – commodity contracts	$	8	$	1	$	13	$	22
	Nuclear decommissioning trust fund:
	Equity securities:
	U.S. large capitalization	$	481	$	—	$	—	$	481
	Debt securities:
	U.S. Treasury and agency securities	—		118		—		118
	Corporate bonds	—		78		—		78
	Other	—		31		—		31
	Total nuclear decommissioning trust fund	$	481	$	227	$	—	$	708	(b)
	Total Ameren	$	489	$	228	$	13	$	730
Ameren Missouri	Derivative assets – commodity contracts(a):
	Fuel oils	$	8	$	—	$	5	$	13
	Power	—		—		7		7
	Total derivative assets – commodity contracts	$	8	$	—	$	12	$	20
	Nuclear decommissioning trust fund:
	Equity securities:
	U.S. large capitalization	$	481	$	—	$	—	$	481
	Debt securities:
	U.S. Treasury and agency securities	—		118		—		118
	Corporate bonds	—		78		—		78
	Other	—		31		—		31
	Total nuclear decommissioning trust fund	$	481	$	227	$	—	$	708	(b)
	Total Ameren Missouri	$	489	$	227	$	12	$	728
Ameren Illinois	Derivative assets – commodity contracts(a):
	Natural gas	$	—	$	1	$	1	$	2
Liabilities:
Ameren	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	—	$	—	$	1	$	1
	Natural gas	1		26		5		32
	Power	—		—		192		192
	Total Ameren	$	1	$	26	$	198	$	225
Ameren Missouri	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	—	$	—	$	1	$	1
	Natural gas			7		—		7
	Power	—		—		2		2
	Total Ameren Missouri	$	—	$	7	$	3	$	10
Ameren Illinois	Derivative liabilities – commodity contracts(a):
	Natural gas	$	1	$	19	$	5	$	25
	Power	—		—		190		190
	Total Ameren Illinois	$	1	$	19	$	195	$	215

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

(b) Balance excludes $6 million of cash and cash equivalents, 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, 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	$	4	$	—	$	3	$	7
	Natural gas	—		—		1		1
	Power	—		1		8		9
	Total derivative assets – commodity contracts	$	4	$	1	$	12	$	17
	Nuclear decommissioning trust fund:
	Equity securities:
	U.S. large capitalization	$	468	$	—	$	—	$	468
	Debt securities:
	U.S. Treasury and agency securities	—		125		—		125
	Corporate bonds	—		82		—		82
	Other	—		25		—		25
	Total nuclear decommissioning trust fund	$	468	$	232	$	—	$	700	(b)
	Total Ameren	$	472	$	233	$	12	$	717
Ameren Missouri	Derivative assets – commodity contracts(a):
	Fuel oils	$	4	$	—	$	3	$	7
	Natural gas	—		—		1		1
	Power	—		1		8		9
	Total derivative assets – commodity contracts	$	4	$	1	$	12	$	17
	Nuclear decommissioning trust fund:
	Equity securities:
	U.S. large capitalization	$	468	$	—	$	—	$	468
	Debt securities:
	U.S. Treasury and agency securities	—		125		—		125
	Corporate bonds	—		82		—		82
	Other	—		25		—		25
	Total nuclear decommissioning trust fund	$	468	$	232	$	—	$	700	(b)
	Total Ameren Missouri	$	472	$	233	$	12	$	717
Liabilities:
Ameren	Derivative liabilities – commodity contracts(a):
	Natural gas	$	1	$	25	$	4	$	30
	Power	—		—		196		196
	Total Ameren	$	1	$	25	$	200	$	226
Ameren Missouri	Derivative liabilities – commodity contracts(a):
	Natural gas	$	—	$	7	$	1	$	8
	Power	—		—		1		1
	Total Ameren Missouri	$	—	$	7	$	2	$	9
Ameren Illinois	Derivative liabilities – commodity contracts(a):
	Natural gas	$	1	$	18	$	3	$	22
	Power	—		—		195		195
	Total Ameren Illinois	$	1	$	18	$	198	$	217

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

(b) Balance excludes $4 million of cash and cash equivalents, 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 and six months ended June 30, 2018 and 2017, the balances and changes in the fair value of Level 3 financial assets and liabilities associated with fuel oils and natural gas were immaterial.

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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 June 30, 2018
Beginning balance at April 1, 2018	$	4		$	(191	)	$	(187	)
Realized and unrealized losses included in regulatory assets/liabilities		(1	)		(2	)		(3	)
Purchases		4			—			4
Settlements		(2	)		3			1
Ending balance at June 30, 2018	$	5		$	(190	)	$	(185	)
Change in unrealized losses related to assets/liabilities held at June 30, 2018	$	—		$	(3	)	$	(3	)
For the three months ended June 30, 2017
Beginning balance at April 1, 2017	$	4		$	(194	)	$	(190	)
Realized and unrealized losses included in regulatory assets/liabilities		(1	)		(1	)		(2	)
Purchases		15			—			15
Settlements		(4	)		3			(1	)
Ending balance at June 30, 2017	$	14		$	(192	)	$	(178	)
Change in unrealized losses related to assets/liabilities held at June 30, 2017	$	—		$	(2	)	$	(2	)
For the six months ended June 30, 2018
Beginning balance at January 1, 2018	$	7		$	(195	)	$	(188	)
Realized and unrealized losses included in regulatory assets/liabilities		(3	)		(1	)		(4	)
Purchases		4			—			4
Settlements		(3	)		6			3
Ending balance at June 30, 2018	$	5		$	(190	)	$	(185	)
Change in unrealized losses related to assets/liabilities held at June 30, 2018	$	(1	)	$	(2	)	$	(3	)
For the six months ended June 30, 2017
Beginning balance at January 1, 2017	$	7		$	(185	)	$	(178	)
Realized and unrealized losses included in regulatory assets/liabilities		(1	)		(11	)		(12	)
Purchases		15			—			15
Settlements		(7	)		4			(3	)
Ending balance at June 30, 2017	$	14		$	(192	)	$	(178	)
Change in unrealized losses related to assets/liabilities held at June 30, 2017	$	—		$	(13	)	$	(13	)

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 and six months ended June 30, 2018 and 2017, 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.

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The following table describes the valuation techniques and unobservable inputs utilized by the Ameren Companies for the fair value of financial assets and liabilities measured at fair value on a recurring basis and classified as Level 3 in the fair value hierarchy for the periods ended June 30, 2018, and December 31, 2017:

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
Level 3 Derivative asset and liability – commodity contracts(a):
2018
	Fuel oils	$	5	$	(1	)	Option model	Volatilities(%)(b)	20 – 34	25
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.12 – 0.85	0.38
								Ameren Missouri credit risk(%)(c)(d)	0.35	(e)
	Natural gas	1		(5		)	Discounted cash flow	Nodal basis ($/mmbtu)(b)	(1.30) – 0.30	(0.90)
								Counterparty credit risk (%)(c)(d)	0.23 – 1	0.81
								Ameren Illinois credit risk (%)(c)(d)	0.35	(e)
	Power(f)	7		(192		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)(g)	24 – 39	27
								Estimated auction price for FTRs ($/MW)(b)	(898) – 1,180	57
								Nodal basis ($/MWh)(g)	(10) – 0	(2)
								Counterparty credit risk (%)(c)(d)	0.91	(e)
								Ameren Illinois credit risk (%)(c)(d)	0.35	(e)
							Fundamental energy production model	Estimated future natural gas prices ($/mmbtu)(b)	3	(e)
								Escalation rate (%)(b)(h)	4	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(b)	5 – 7	6
2017
	Fuel oils	$	3	$	—		Option model	Volatilities (%)(b)	20 – 26	22
							Discounted cash flow	Counterparty credit risk (%)(c)(d)	0.12 – 0.72	0.41
								Ameren Missouri credit risk (%)(c)(d)	0.37	(e)
	Natural gas	1		(4		)	Option model	Volatilities (%)(b)	26 – 46	37
								Nodal basis ($/mmbtu)(c)	(0.50) – (0.30)	(0.40)
							Discounted cash flow	Nodal basis ($/mmbtu)(b)	(1.20) – 0.10	(1)
								Counterparty credit risk (%)(c)(d)	0.37 – 0.92	0.53
								Ameren credit risk (%)(c)(d)	0.37	(e)
	Power(f)	8		(196		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)(g)	24 – 46	28
								Estimated auction price for FTRs ($/MW)(b)	(65) – 1,823	251
								Nodal basis ($/MWh)(g)	(10) – 0	(2)
								Counterparty credit risk (%)(c)(d)	0.28	(e)
								Ameren Illinois credit risk (%)(c)(d)	0.37	(e)
							Fundamental energy production model	Estimated future natural gas prices ($/mmbtu)(b)	3 – 4	3
								Escalation rate (%)(b)(h)	5	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(b)	5 – 7	6

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

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

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

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

(e) Not applicable.

(f) Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2022 for June 30, 2018, and through 2021 for December 31, 2017. Valuations beyond 2022 for June 30, 2018, and 2021 for December 31, 2017, use fundamentally modeled pricing by month for peak and off-peak demand.

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

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

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The following table sets forth, by level within the fair value hierarchy, the carrying amount and fair value of financial assets and liabilities disclosed, but not carried, at fair value as of June 30, 2018, and December 31, 2017:

	June 30, 2018
	Carrying Amount			Fair Value
				Level 1		Level 2		Level 3			Total
Ameren:
Cash, cash equivalents, and restricted cash	$	96		$	96	$	—	$	—		$	96
Investments in held-to-maturity debt securities(a)	276			—		276		—			276
Short-term debt	506			—		506		—			506
Long-term debt (including current portion)(a)	8,460		(b)	—		8,411		438		(c)	8,849
Preferred stock(d)	142			—		140		—			140
Ameren Missouri:
Cash, cash equivalents, and restricted cash	$	25		$	25	$	—	$	—		$	25
Advances to money pool	66			—		66		—			66
Investments in held-to-maturity debt securities(a)	276			—		276		—			276
Long-term debt (including current portion)(a)	4,202		(b)	—		4,544		—			4,544
Preferred stock	80			—		79		—			79
Ameren Illinois:
Cash, cash equivalents, and restricted cash	$	57		$	57	$	—	$	—		$	57
Borrowings from money pool	31			—		31		—			31
Long-term debt (including current portion)	3,113		(b)	—		3,187		—			3,187
Preferred stock	62			—		61		—			61
	December 31, 2017
Ameren:
Cash, cash equivalents, and restricted cash	$	68		$	68	$	—	$	—		$	68
Investments in held-to-maturity debt securities(a)	276			—		276		—			276
Short-term debt	484			—		484		—			484
Long-term debt (including current portion)(a)	7,935		(b)	—		8,531		—			8,531
Preferred stock(c)	142			—		131		—			131
Ameren Missouri:
Cash, cash equivalents, and restricted cash	$	7		$	7	$	—	$	—		$	7
Investments in held-to-maturity debt securities(a)	276			—		276		—			276
Short-term debt	39			—		39		—			39
Long-term debt (including current portion)(a)	3,961		(b)	—		4,348		—			4,348
Preferred stock	80			—		80		—			80
Ameren Illinois:
Cash, cash equivalents, and restricted cash	$	41		$	41	$	—	$	—		$	41
Short-term debt	62			—		62		—			62
Long-term debt (including current portion)	2,830		(b)	—		3,028		—			3,028
Preferred stock	62			—		51		—			51

(a) Ameren and Ameren Missouri have investments in industrial revenue bonds, classified as held-to-maturity and recorded in “Other Assets,” that are equal to the capital lease obligation for CTs leased from the city of Bowling Green and Audrain County. As of June 30, 2018, and December 31, 2017, the carrying amount of both the investments in industrial revenue bonds and the capital lease obligations approximated fair value.

(b) Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $56 million, $23 million, and $27 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of June 30, 2018. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $50 million, $20 million, and $24 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2017.

(c) The Level 3 fair value amount consists of ATXI’s senior unsecured notes. In the first quarter of 2018, the amount was transferred to Level 3 because inputs to the valuation model became unobservable during the period.

(d) 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 natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between Ameren’s subsidiaries are reported as affiliate transactions on their individual financial statements, but those transactions are eliminated in consolidation for Ameren’s consolidated financial statements. For a discussion of our material related-party agreements and money pool arrangements, see Note 13 – Related-party Transactions and Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of the Form 10-K.

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Electric Power Supply Agreement

In April 2018, 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 2018, Ameren Missouri and Ameren Illinois entered into an energy product agreement by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, 110,000 megawatthours at an average price of $32 per megawatthour during the period of June 2019 through September 2020.

The following table presents the impact on Ameren Missouri and Ameren Illinois of related-party transactions for the three and six months ended June 30, 2018 and 2017:

				Three Months				Six Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2018	$	3	$	(a)	$	6	$	(a)
agreements with Ameren Illinois		2017		6		(a)		17		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2018		6		1		11		2
rent and facility services		2017		6		1		13		2
Ameren Missouri and Ameren Illinois	Operating Revenues	2018		(b)		(b)		(b)		(b)
miscellaneous support services		2017		(b)		1		(b)		1
Total Operating Revenues		2018	$	9	$	1	$	17	$	2
		2017		12		2		30		3
Ameren Illinois power supply	Purchased Power	2018	$	(a)	$	3	$	(a)	$	6
agreements with Ameren Missouri		2017		(a)		6		(a)		17
Ameren Illinois transmission	Purchased Power	2018		(a)		1		(a)		1
services with ATXI		2017		(a)		1		(a)		1
Total Purchased Power		2018	$	(a)	$	4	$	(a)	$	7
		2017		(a)		7		(a)		18
Ameren Services support services	Other Operations and Maintenance	2018	$	32	$	30	$	65	$	60
agreement		2017		34		34		69		66
Money pool borrowings (advances)	Interest Charges/ Other Income, Net	2018	$	(b)	$	(b)	$	(b)	$	(b)
		2017		(b)		(b)		(b)		(b)

(a) Not applicable.

(b) Amount less than $1 million.

NOTE 9 – COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax, and regulatory proceedings before various courts, regulatory commissions, authorities, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements in this report and in the 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 13 – Related-party Transactions, and Note 14 – Commitments and Contingencies under Part II, Item 8, of the Form 10-K. See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 8 – Related-party Transactions, and Note 10 – Callaway Energy Center of this report.

Other Obligations

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. Ameren Missouri and Ameren Illinois also have entered into various long-term commitments for purchased power and natural gas for distribution. The table below presents our estimated minimum fuel, purchased power, and other commitments for fuel at June 30, 2018. Ameren’s and Ameren Illinois’ purchased power commitments include the Ameren Illinois agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services, among other agreements, at June 30, 2018.

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	Coal		Natural Gas(a)		Nuclear Fuel		Purchased Power(b)(c)		Methane Gas		Other		Total
Ameren:(d)
2018	$	181	$	148	$	51	$	130	$	2	$	56	$	568
2019	246		210		27		122		4		47		656
2020	85		125		38		30		4		62		344
2021	27		61		57		5		5		28		183
2022	—		12		12		—		5		26		55
Thereafter	—		39		62		—		58		93		252
Total	$	539	$	595	$	247	$	287	$	78	$	312	$	2,058
Ameren Missouri:
2018	$	181	$	22	$	51	$	—	$	2	$	39	$	295
2019	246		38		27		—		4		29		344
2020	85		30		38		—		4		44		201
2021	27		14		57		—		5		25		128
2022	—		5		12		—		5		26		48
Thereafter	—		17		62		—		58		74		211
Total	$	539	$	126	$	247	$	—	$	78	$	237	$	1,227
Ameren Illinois:
2018	$	—	$	126	$	—	$	130	$	—	$	5	$	261
2019	—		172		—		122		—		9		303
2020	—		95		—		30		—		9		134
2021	—		47		—		5		—		—		52
2022	—		7		—		—		—		—		7
Thereafter	—		22		—		—		—		—		22
Total	$	—	$	469	$	—	$	287	$	—	$	23	$	779

(a) Includes amounts for generation and for distribution.

(b) The purchased power amounts for Ameren and Ameren Illinois exclude agreements for renewable energy credits through 2032 with various renewable energy suppliers due to the contingent nature of the payment amounts.

(c) The purchased power amounts for Ameren and Ameren Missouri exclude a 102-megawatt power purchase agreement with a wind farm operator, which expires in 2024, due to the contingent nature of the payment amounts.

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

In January 2018, as required by the FEJA, Ameren Illinois entered into 10-year agreements to acquire zero emission credits. Annual zero emission credit commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. The amounts above reflect Ameren Illinois’ commitment to acquire zero emission credits of approximately $57 million through May 2019.

In April 2018, Ameren Illinois conducted procurement events, administered by the IPA, to purchase energy products through May 2021. In the April 2018 procurement event, Ameren Illinois contracted to purchase 3,956,200 megawatthours of energy products for $112 million from June 2018 through May 2021, which is reflected in the amounts above. See Note 8 – Related-party Transactions for additional information regarding energy product agreements between Ameren Missouri and Ameren Illinois as a result of the April 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 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, 2017, Ameren Missouri’s fossil fuel-fired energy centers represented 17% and 33% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations that apply to air emissions from the electric utility industry include the NSPS, the CSAPR, the MATS, and the 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, and CO₂ emissions from new power plants. Water intake and discharges from power plants are regulated under the Clean Water Act. Such regulation could require modifications to water intake structures or more stringent limitations on wastewater discharges at Ameren Missouri’s energy centers, either of which could result in significant capital expenditures. The management and disposal of coal ash is regulated under the CCR Rule, which will require the closure of surface

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impoundments and the installations of dry ash handling systems at several of Ameren Missouri’s energy centers. The individual or combined effects of existing environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers. 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 air emission regulations 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 $325 million to $425 million from 2018 through 2022 in order to comply with existing environmental regulations. Additional environmental controls beyond 2022 could be required. This estimate of capital expenditures includes expenditures required by the CCR regulations, by the Clean Water Act rule applicable to cooling water intake structures at existing power plants, and by effluent limitation guidelines applicable to steam electric generating units, all of which are 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 substantially revise regulatory obligations, exactly which compliance strategies will be used and their ultimate cost, among other things.

The following sections describe the more significant environmental laws and rules and environmental enforcement and remediation matters that affect or could affect our operations. The EPA has initiated an administrative review of several regulations and proposed regulation amendments, including to the effluent limitation guidelines and the CCR Rule, which could ultimately result in the revision of all or part of such rules.

Clean Air Act

Federal and state laws, including CSAPR, regulate emissions of SO₂ and NO_x through emission source reductions and 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 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 the Clean Power Plan, which would have established CO₂ emissions standards applicable to existing power plants. The United States Supreme Court stayed the rule in February 2016, pending various legal challenges. In July 2018, the Office of Management and Budget received the EPA’s proposal to repeal and replace the Clean Power Plan. We expect that the EPA's Clean Power Plan replacement rule, including anticipated future emissions regulation, will be released and made publicly available later this year following the Office of Management and Budget’s review. We cannot predict the outcome of EPA’s rulemaking or the outcome of legal challenges related to such future rulemakings.

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 then proceeded to the second phase to determine the actions required to remedy the violations found in the liability phase. The EPA previously withdrew all claims for penalties and fines. No date has been set by the district court for a trial on the remedy phase of the litigation. At the conclusion of both phases of the litigation, Ameren Missouri intends to appeal the liability ruling to the United States Court of Appeals for the Eighth Circuit.

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 July 2018, the United States Court of Appeals for the Second Circuit upheld the EPA’s Section 316(b) 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

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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. The rule will be implemented between 2018 and 2023, during the permit renewal process of each energy center’s water discharge permit.

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 September 2017, the EPA published a rule that postponed the compliance dates by two years for the limitations applicable to two specific waste streams so that it could potentially revise those standards. Ameren Missouri is in the process of constructing wastewater treatment facilities at three of its energy centers. The cost to complete these facilities is included in the capital expenditures, discussed above, that Ameren and Ameren Missouri estimate they will need to make in order to comply with existing environmental regulations.

CCR Management

In 2015, the EPA issued the CCR Rule, which established 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. In July 2018, the EPA issued revisions to the CCR Rule that extended certain compliance deadlines and indicated that additional revisions to the CCR Rule are likely. Ameren and Ameren Missouri have AROs of $141 million recorded on their respective balance sheets as of June 30, 2018, associated with CCR storage facilities that reflect the regulations issued in 2015. Ameren plans to close these CCR storage facilities between 2018 and 2023. The recent EPA revisions do not affect Ameren Missouri’s plan. Ameren Missouri estimates it will need to make capital expenditures of $300 million to $350 million from 2018 through 2022 to implement its CCR management compliance plan, which includes installation of dry ash handling systems, waste water treatment facilities, and groundwater monitoring equipment.

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 June 30, 2018, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois, the majority of which have been investigated, remediated, and closed. Ameren Illinois estimates it could substantially conclude remediation efforts by 2023. The ICC allows Ameren Illinois to recover such remediation and related litigation costs from its electric and natural gas utility customers through environmental cost riders. Costs are subject to annual prudence review by the ICC. As of June 30, 2018, Ameren Illinois estimated the obligation related to these former MGP sites at $165 million to $236 million. Ameren and Ameren Illinois recorded a liability of $165 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, technical feasibility of certain remediation measures, regulatory changes, disposal costs, and site accessibility. The actual costs and timing of completion 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. 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. Ameren Missouri is the owner of one of the sites and in July 2018 reached an agreement with the EPA and Solutia, Inc., the primary potentially responsible party for Sauget Area 2, which limits Ameren Missouri’s cleanup obligation to the site it owns. Remediation efforts at the site are expected to occur in 2019. As of June 30, 2018, 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.

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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 paid by Ameren Missouri and other utilities that own and operate those energy centers to 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 2014.

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. Ameren Missouri’s lawsuit against the DOE resulted in a settlement agreement that provides for annual reimbursement of additional spent fuel storage and related costs. For the six months ended June 30, 2018 and 2017, 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. 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.

Supplier of Fuel Assemblies

The Callaway energy center uses nuclear fuel assemblies fabricated by Westinghouse, which is 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. As part of its bankruptcy plan, Westinghouse filed a schedule of assumed contracts, which includes all current contracts between Westinghouse and Ameren Missouri, including the contract for fabrication of fuel assemblies for the Callaway energy center. In April 2018, the bankruptcy court approved Westinghouse’s bankruptcy plan, which included the assumption of its contracts with Ameren Missouri. The plan is expected to become effective in the third quarter of 2018. At this time, Ameren and Ameren Missouri believe the remainder of 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. 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.

Decommissioning

Electric 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. An updated cost study and funding analysis was filed with the MoPSC in September 2017 and reflected within the ARO. In January 2018, the MoPSC approved no change in electric rates for decommissioning costs based on Ameren Missouri’s updated cost study and funding analysis.

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.

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Insurance

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center as of June 30, 2018. 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 2018.

Type and Source of Coverage	Maximum Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	450		$	—
Pool participation	12,604		(a)	127		(b)
	$	13,054	(c)	$	127
Property damage:
NEIL and EMANI	$	3,200	(d)	$	27	(e)
Replacement power:
NEIL	$	490	(f)	$	7	(e)

(a) Provided through mandatory participation in an industrywide retrospective premium assessment program. The maximum coverage available is dependent on the number of United States commercial reactors participating in the 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 insurance for nonradiation events. EMANI provides $490 million in property damage insurance 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.

NOTE 11 – RETIREMENT BENEFITS

In March 2017, the FASB issued authoritative guidance that requires an entity to report, including on a retrospective basis, the non-service cost or income components of net periodic benefit cost separately from the service cost component and outside of operating income. The Ameren Companies adopted this guidance, effective January 1, 2018, and as a result, $22 million, $12 million, and $4 million of net benefit income has been retrospectively reclassified from "Operating Expenses – Other operations and maintenance" to “Other Income, Net” on Ameren's, Ameren Missouri's, and Ameren Illinois' respective statements of income for the six months ended June 30, 2017. Net benefit income of $10 million, $6 million, and $1 million has been similarly retrospectively reclassified on Ameren's, Ameren Missouri's, and Ameren Illinois' respective statements of income for the three months ended June 30, 2017.

The guidance also requires an entity to capitalize only 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. This change in the capitalization of net benefit costs is not expected to affect our ability to recover total net benefit cost through customer rates.

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The following table presents the components of the net periodic benefit cost (income), prior to capitalization, incurred for Ameren’s pension and postretirement benefit plans for the three and six months ended June 30, 2018 and 2017:

	Pension Benefits												Postretirement Benefits
	Three Months						Six Months						Three Months						Six Months
	2018			2017			2018			2017			2018			2017			2018			2017
Service cost(a)	$	25		$	23		$	50		$	46		$	5		$	5		$	10		$	10
Non-service cost components:
Interest cost	42			45			84			90			9			11			20			23
Expected return on plan assets	(69		)	(65		)	(138		)	(131		)	(19		)	(18		)	(38		)	(37		)
Amortization of:
Prior service benefit	—			—			—			—			(1		)	(1		)	(2		)	(2		)
Actuarial loss (gain)	18			13			34			27			(3		)	(1		)	(3		)	(3		)
Total non-service cost components(b)	(9		)	(7		)	(20		)	(14		)	(14		)	(9		)	(23		)	(19		)
Net periodic benefit cost (income)	$	16		$	16		$	30		$	32		$	(9	)	$	(4	)	$	(13	)	$	(9	)

(a) Service cost, net of capitalization, is reflected in “Operating Expenses – Other operations and maintenance” on Ameren’s statement of income.

(b) 2018 amounts and the non-capitalized portion of 2017’s non-service cost components, as discussed above, are reflected in “Other Income, Net” on Ameren’s statement of income. See Note 5 – Other Income, Net for additional information.

Ameren Missouri and Ameren Illinois are responsible for their respective shares of Ameren’s pension and postretirement costs. The following table presents the respective share of net periodic pension and other postretirement benefit costs (income) incurred for the three and six months ended June 30, 2018 and 2017:

	Pension Benefits								Postretirement Benefits
	Three Months				Six Months				Three Months						Six Months
	2018		2017		2018		2017		2018			2017			2018			2017
Ameren Missouri(a)	$	6	$	6	$	11	$	12	$	—		$	(1	)	$	—		$	(2	)
Ameren Illinois	10		10		19		20		(9		)	(3		)	(13		)	(7		)
Ameren(a)	$	16	$	16	$	30	$	32	$	(9	)	$	(4	)	$	(13	)	$	(9	)

(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.

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 primarily comprises the aggregated electric transmission businesses of Ameren Illinois and ATXI. The category called Other primarily includes Ameren (parent) 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, Ameren Illinois, and ATXI.

Segment operating revenues and a majority of operating expenses are directly recognized and incurred by Ameren Illinois at 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, other retail electric suppliers, and wholesale customers. 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 in Ameren Transmission’s and Ameren Illinois Transmission’s operating revenues. An intersegment elimination at Ameren and Ameren Illinois occurs to eliminate these transmission revenues and expenses.

The following tables present revenues, net income attributable to common shareholders, and capital expenditures by segment at Ameren and Ameren Illinois for the three and six months ended June 30, 2018 and 2017. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.

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Ameren

Three Months	Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission			Other			Intersegment Eliminations			Consolidated
2018
External revenues	$	946	$	386	$	142	$	89		$	—		$	—		$	1,563
Intersegment revenues	9		1		—		14			—			(24		)	—
Net income attributable to Ameren common shareholders	168		33		7		36		(a)	(5		)	—			239
Capital expenditures	205		132		66		130			(2		)	2			533
2017
External revenues	$	922	$	387	$	134	$	92		$	2		$	—		$	1,537
Intersegment revenues	12		2		—		13			—			(27		)	—
Net income attributable to Ameren common shareholders	120		33		5		34		(a)	1			—			193
Capital expenditures	159		122		58		156			1			(2		)	494
Six Months
2018
External revenues	$	1,730	$	785	$	453	$	180		$	—		$	—		$	3,148
Intersegment revenues	17		2		—		27			—			(46		)	—
Net income attributable to Ameren common shareholders	206		66		49		73		(a)	(4		)	—			390
Capital expenditures	454		254		126		275			5			(2		)	1,112
2017
External revenues	$	1,695	$	771	$	398	$	188		$	—		$	—		$	3,052
Intersegment revenues	30		3		—		19			—			(52		)	—
Net income attributable to Ameren common shareholders	125		63		38		68		(a)	1			—			295
Capital expenditures	355		242		109		290			5			(3		)	998

(a) Ameren Transmission earnings include an allocation of financing costs from Ameren (parent).

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Ameren Illinois

Three Months	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Intersegment Eliminations			Total Ameren Illinois
2018
External revenues	$	387	$	142	$	49	$	—		$	578
Intersegment revenues	—		—		13		(13		)	—
Net income available to common shareholder	33		7		22		—			62
Capital expenditures	132		66		104		—			302
2017
External revenues	$	389	$	134	$	53	$	—		$	576
Intersegment revenues	—		—		12		(12		)	—
Net income available to common shareholder	33		5		19		—			57
Capital expenditures	122		58		77		—			257
Six Months
2018
External revenues	$	787	$	453	$	98	$	—		$	1,338
Intersegment revenues	—		—		26		(26		)	—
Net income available to common shareholder	66		49		42		—			157
Capital expenditures	254		126		222		—			602
2017
External revenues	$	774	$	398	$	107	$	—		$	1,279
Intersegment revenues	—		—		18		(18		)	—
Net income available to common shareholder	63		38		35		—			136
Capital expenditures	242		109		133		—			484

The following tables present disaggregated revenues by segment at Ameren and Ameren Illinois for the three and six months ended June 30, 2018 and 2017. Economic factors affect the nature, timing, amount, and uncertainty of revenues and cash flows in a similar manner across customer classes. Revenues from alternative revenue programs have a similar distribution among customer classes as revenues from contracts with customers. Other revenues not associated with contracts with customers are presented in the Other customer classification, along with electric transmission and off-system revenues.

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Ameren

Three Months	Ameren Missouri				Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission		Other		Intersegment Eliminations			Consolidated
2018
Residential	$	432			$	221	$	—	$	—	$	—	$	—		$	653
Commercial	364				126		—		—		—		—			490
Industrial	87				33		—		—		—		—			120
Other	47			(a)	7		—		103		—		(24		)	133		(a)
Total electric revenues	$	930			$	387	$	—	$	103	$	—	$	(24	)	$	1,396
Residential	$	13			$	—	$	97	$	—	$	—	$	—		$	110
Commercial	6				—		26		—		—		—			32
Industrial	—				—		5		—		—		—			5
Other	6				—		14		—		—		—			20
Total gas revenues	25				—		142		—		—		—			167
Total revenues(b)	$	955			$	387	$	142	$	103	$	—	$	(24	)	$	1,563
2017
Residential	$	358			$	208	$	—	$	—	$	—	$	—		$	566
Commercial	332				129		—		—		—		—			461
Industrial	84				28		—		—		—		—			112
Other	138				24		—		105		2		(26		)	243
Total electric revenues	$	912			$	389	$	—	$	105	$	2	$	(26	)	$	1,382
Residential	$	10			$	—	$	84	$	—	$	—	$	—		$	94
Commercial	4				—		24		—		—		—			28
Industrial	1				—		2		—		—		—			3
Other	7				—		24		—		—		(1		)	30
Total gas revenues	$	22			$	—	$	134	$	—	$	—	$	(1	)	$	155
Total revenues(b)	$	934			$	389	$	134	$	105	$	2	$	(27	)	$	1,537
Six Months
2018
Residential	$	764			$	440	$	—	$	—	$	—	$	—		$	1,204
Commercial	616				250		—		—		—		—			866
Industrial	148				68		—		—		—		—			216
Other	143			(a)	29		—		207		—		(46		)	333		(a)
Total electric revenues	$	1,671			$	787	$	—	$	207	$	—	$	(46	)	$	2,619
Residential	$	54			$	—	$	340	$	—	$	—	$	—		$	394
Commercial	22				—		93		—		—		—			115
Industrial	2				—		11		—		—		—			13
Other	(2		)		—		9		—		—		—			7
Total gas revenues	$	76			$	—	$	453	$	—	$	—	$	—		$	529
Total revenues(b)	$	1,747			$	787	$	453	$	207	$	—	$	(46	)	$	3,148
2017
Residential	$	644			$	427	$	—	$	—	$	—	$	—		$	1,071
Commercial	562				262		—		—		—		—			824
Industrial	142				56		—		—		—		—			198
Other	311				29		—		207		—		(51		)	496
Total electric revenues	$	1,659			$	774	$	—	$	207	$	—	$	(51	)	$	2,589
Residential	$	40			$	—	$	287	$	—	$	—	$	—		$	327
Commercial	16				—		79		—		—		—			95
Industrial	2				—		5		—		—		—			7
Other	8				—		27		—		—		(1		)	34
Total gas revenues	$	66			$	—	$	398	$	—	$	—	$	(1	)	$	463
Total revenues(b)	$	1,725			$	774	$	398	$	207	$	—	$	(52	)	$	3,052

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(a) Includes $37 million and $47 million for the three and six months ended June 30, 2018, respectively, for the reduction to revenue for the excess amounts collected in rates related to the TCJA from January 1, 2018, through June 30, 2018. See Note 2 – Rate and Regulatory Matters for additional information.

(b) The following table presents revenues from alternative revenue programs and other revenues not from contracts with customers for the three and six months ended June 30, 2018 and 2017:

Three Months	Ameren Missouri			Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas			Ameren Transmission			Consolidated
2018
Revenues from alternative revenue programs	$	(5	)	$	15	$	(5	)	$	(5	)	$	—
Other revenues not from contracts with customers	5			3		—			—			8
2017
Revenues from alternative revenue programs	$	(7	)	$	16	$	1		$	2		$	12
Other revenues not from contracts with customers	3			1		1			—			5
Six Months
2018
Revenues from alternative revenue programs	$	(9	)	$	46	$	(8	)	$	(9	)	$	20
Other revenues not from contracts with customers	19			13		1			—			33
2017
Revenues from alternative revenue programs	$	(14	)	$	49	$	12		$	7		$	54
Other revenues not from contracts with customers	7			3		2			—			12

Ameren Illinois

Three Months	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Intersegment Eliminations			Total Ameren Illinois
2018
Residential	$	221	$	97	$	—	$	—		$	318
Commercial	126		26		—		—			152
Industrial	33		5		—		—			38
Other	7		14		62		(13		)	70
Total revenues(a)	$	387	$	142	$	62	$	(13	)	$	578
2017
Residential	$	208	$	84	$	—	$	—		$	292
Commercial	129		24		—		—			153
Industrial	28		2		—		—			30
Other	24		24		65		(12		)	101
Total revenues(a)	$	389	$	134	$	65	$	(12	)	$	576
Six Months
2018
Residential	$	440	$	340	$	—	$	—		$	780
Commercial	250		93		—		—			343
Industrial	68		11		—		—			79
Other	29		9		124		(26		)	136
Total revenues(a)	$	787	$	453	$	124	$	(26	)	$	1,338
2017
Residential	$	427	$	287	$	—	$	—		$	714
Commercial	262		79		—		—			341
Industrial	56		5		—		—			61
Other	29		27		125		(18		)	163
Total revenues(a)	$	774	$	398	$	125	$	(18	)	$	1,279

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(a) The following table presents revenues from alternative revenue programs and other revenues not from contracts with customers for the Ameren Illinois segments for the three and six months ended June 30, 2018 and 2017:

Three Months	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas			Ameren Illinois Transmission			Consolidated
2018
Revenues from alternative revenue programs	$	15	$	(5	)	$	(5	)	$	5
Other revenues not from contracts with customers	3		—			—			3
2017
Revenues from alternative revenue programs	$	16	$	1		$	2		$	19
Other revenues not from contracts with customers	1		1			—			2
Six Months
2018
Revenues from alternative revenue programs	$	46	$	(8	)	$	(9	)	$	29
Other revenues not from contracts with customers	13		1			—			14
2017
Revenues from alternative revenue programs	$	49	$	12		$	5		$	66
Other revenues not from contracts with customers	3		2			—			5

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 whose primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Ameren also has other subsidiaries that conduct other activities, such as providing shared services. Ameren evaluates competitive electric transmission investment opportunities 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 and Mark Twain projects, and placed the Spoon River project in service in February 2018.

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 $239 million in the three months ended June 30, 2018, compared with $193 million in the year-ago period. Net income attributable to Ameren common shareholders was $390 million in the six months ended June 30, 2018, compared with $295 million in the year-ago period. Net income in the three and six months ended June 30, 2018, compared to the year-ago periods, was favorably affected by colder winter and warmer early summer temperatures experienced in 2018, as well as an increase in base rates and lower base level expenses at Ameren Missouri, pursuant to the MoPSC’s March 2017 electric rate order. Earnings were also favorably affected by increased infrastructure investments in the Ameren Transmission, Ameren Illinois Electric Distribution, and

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Ameren Illinois Natural Gas segments. Net income was unfavorably affected in the three and six months ended June 30, 2018, compared to the year-ago period, by increased other operation and maintenance expenses and by increased depreciation and amortization expenses, both primarily at Ameren Missouri.

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 six months of 2018, Ameren invested $655 million of capital expenditures in its FERC rate-regulated electric transmission and Illinois electric and natural gas distribution businesses.

In June 2018, legislation was enacted that enhanced Ameren Missouri’s electric regulatory framework. The enactment of Missouri Senate Bill 564 supports an incremental $1 billion of grid modernization investments through 2023. Upon Ameren Missouri’s expected PISA election, the legislation will allow deferral, for future recovery, of 85% of the depreciation expense and return on rate base related to certain property, plant, and equipment placed-in-service after August 28, 2018, and not included in base rates, which will mitigate the impacts of regulatory lag between regulatory rate reviews. Upon approval in a regulatory rate review, PISA deferrals would be added to rate base prospectively and earn a return based on Ameren Missouri’s weighted-average cost of capital over a recovery period of 20 years. Additional provisions apply when electing the use of PISA, which for Ameren Missouri, would include limiting electric rate increases and an electric base rate freeze until April 2020. Both the rate increase limitation and PISA would be effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028. The legislation maintains strong MoPSC oversight and consumer protections while supporting Ameren Missouri’s ability to strengthen and modernize Missouri’s electric grid.

In the second quarter of 2018, Ameren Missouri entered into an agreement with a subsidiary of Terra-Gen, LLC to acquire a 400-megawatt wind generation facility after construction. The facility is expected to be located in northeastern Missouri and to be completed in 2020. The acquisition is subject to certain conditions, including the issuance of a certificate of convenience and necessity by the MoPSC, obtaining a MISO transmission interconnection agreement, and approval by the FERC. Ameren Missouri has filed for the certificate of convenience and necessity with the MoPSC. This facility would help Ameren Missouri to comply with the state renewable energy standard.In addition, Ameren Missouri requested the MoPSC to authorize a proposed RESRAM that would allow Ameren Missouri to adjust customer rates, including recovery of interest at a short-term borrowing rate, on an annual basis without a traditional regulatory rate review. The RESRAM is designed to mitigate the impacts of regulatory lag for investments in wind generation and other renewables by providing more timely recovery of costs and would provide Ameren Missouri a greater opportunity to earn its allowed return on investment. Ameren Missouri anticipates a decision by January 2019 related to the certificate of convenience and necessity and proposed RESRAM.Further, Ameren Missouri is also pursuing the acquisition of an additional 300 megawatts of wind generation with multiple wind developers, which would allow Ameren Missouri to achieve compliance with Missouri's renewable energy standard.

Ameren Illinois invested $380 million in electric distribution and natural gas infrastructure projects in the first six months of 2018. In April 2018, Ameren Illinois filed its annual electric distribution service formula rate update to establish the revenue requirement to be used for 2019 rates with the ICC. In July 2018, the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing, recommending an amount comparable to Ameren Illinois’ filing. Pending ICC approval, this update filing will result in a$72 millionincrease in Ameren Illinois’ electric distribution service rates beginning in January 2019.This update reflects an increase to the annual formula rate based on 2017 actual costs and expected net plant additions for 2018 and an increase to include the 2017 revenue requirement reconciliation adjustment. It also includes a decrease for the conclusion of the 2016 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2018. An ICC decision on the revenue requirement to be used for 2019 rates is expected by December 2018.

In January 2018, Ameren Illinois filed a request with the ICC seeking approval to increase its annual rates for natural gas delivery service. In July 2018, Ameren Illinois and the ICC staff filed a stipulation and agreement with the ICC that, pending ICC approval, would result in an annual natural gas rate increase of $37 million, based on the terms of the agreement and subject to adjustments for updated rate case and other postretirement benefit expenses. This increase in annual rates includes a 9.87% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion. It also reflects the reduction in the federal corporate income tax rate as a result of the TCJA, as well as the increase in the Illinois corporate income tax rate that became effective in July 2017, which decreased the annual rates by approximately $17 million. A decision by the ICC in this proceeding is required by December 2018, with new rates expected to be effective in January 2019.

In the first six months of 2018, Ameren Transmission invested $275 million in FERC rate-regulated electric transmission projects, including the Illinois Rivers project, the Spoon River project, and Ameren Illinois’ transmission projects to maintain and improve reliability. ATXI’s Spoon River project, located in northwest Illinois, was placed in service in February 2018. ATXI’s construction activities for its Illinois Rivers project are continuing on schedule, and the last section of this project is expected to be completed by the end of 2019. Related to ATXI’s Mark Twain project, construction activities began in the second quarter of 2018 with completion of the project expected by the end of 2019.

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RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Economic conditions, energy-efficiency investments by our customers and by 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, within the frameworks established by our regulators. In 2018, our revenues include a reduction for the pass through to customers of reduced income taxes resulting from TCJA, which is primarily offset by a reduction in income tax expense.

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 the variance in net energy costs from the amount set in base rates without a traditional regulatory rate review, subject to MoPSC prudence reviews, with the remaining 5% of changes retained by Ameren Missouri. 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. In addition, Ameren Missouri’s MEEIA customer energy-efficiency program costs, the throughput disincentive, and any performance incentive are recoverable through the MEEIA cost recovery mechanism without a traditional regulatory rate review. 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 Missouri employs other cost recovery mechanisms, including a pension and postretirement benefit cost tracker, an uncertain tax position tracker, a renewable energy standard cost tracker, and a solar rebate program tracker. Each of these trackers allows Ameren Missouri to defer the difference between actual costs incurred and costs included in customer rates as a regulatory asset or regulatory liability. The difference will be reflected in base rates in a subsequent MoPSC rate order.

Ameren Illinois’ electric distribution service rates are reconciled annually to its actual revenue requirement and allowed return on equity, under a formula ratemaking process effective through 2022. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement. The regulatory balance is then collected from, or refunded to, customers within two years.

The electric customer energy-efficiency rider provides Ameren Illinois’ electric distribution service business with recovery of, and return on, energy-efficiency investments. The QIP rider provides Ameren Illinois’ natural gas business with recovery of, and a return on, qualifying infrastructure plant investments that are placed in service between regulatory rate reviews.

Ameren Illinois’ electric distribution service revenue requirement is based on recoverable costs, year-end rate base, a capital structure of 50% common equity, and a return on equity. Under the formula ratemaking frameworks for both its electric distribution service and its electric energy-efficiency investments, the return on equity component is equal to the calendar year average of the monthly yields of 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual return on equity is directly correlated to the yields on such bonds. Additionally, Ameren Illinois recovers, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes.

Ameren Illinois’ electric distribution service business has cost recovery mechanisms for power purchased and transmission services incurred on behalf of its customers, renewable energy credit compliance, and zero emission credits. 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. Ameren Illinois employs other cost recovery mechanisms for natural gas customer energy-efficiency program costs and certain environmental costs, as well as bad debt expenses and costs of certain asbestos-related claims not recovered in base rates.

FERC’s electric transmission formula rate framework provides for an annual reconciliation of the electric transmission service revenue requirement, which reflects the actual recoverable costs incurred and the 13-month average rate base for a given year, with the revenue requirement in customer rates, including an allowed return on equity. Ameren Illinois and ATXI use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These rates are updated each January with forecasted information. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement. The regulatory balance is collected from, or

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refunded 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.

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 and six months ended June 30, 2018 and 2017:

	Three Months				Six Months
	2018		2017		2018		2017
Net income attributable to Ameren common shareholders	$	239	$	193	$	390	$	295
Earnings per common share – diluted	0.97		0.79		1.59		1.21

Net income attributable to Ameren common shareholders increased $46 million, or 18 cents per diluted share, in the three months ended June 30, 2018, compared with the year-ago period. The increase was primarily due to net income increases of $48 million, $2 million, and $2 million at Ameren Missouri, Ameren Illinois Natural Gas, and Ameren Transmission, respectively. The increase was partially offset by a net loss of $5 million for activity not reported as part of a segment, primarily at Ameren (parent), compared with net income of $1 million in the same period in 2017.

Net income attributable to Ameren common shareholders increased $95 million, or 38 cents per diluted share, in the six months ended June 30, 2018, compared with the year-ago period. The increase was primarily due to net income increases of $81 million, $11 million, $5 million, and $3 million at Ameren Missouri, Ameren Illinois Natural Gas, Ameren Transmission, and Ameren Illinois Electric Distribution, respectively. The increase was partially offset by a net loss of $4 million for activity not reported as part of a segment, primarily at Ameren (parent), compared with net income of $1 million in the same period in 2017.

Earnings per diluted share were favorably affected in the three and six months ended June 30, 2018, compared to the year-ago periods (except where a specific period is referenced), by:

• increased demand in 2018 at Ameren Missouri, primarily due to colder winter and warmer early summer temperatures experienced in 2018 (estimated at 24 cents per share and 32 cents per share, respectively);

• increased base rates and lower base level of expenses at Ameren Missouri, pursuant to the MoPSC’s March 2017 electric rate order (9 cents per share for the six months ended June 30, 2018);

• decreased financing costs at Ameren Missouri, primarily due to lower interest rates (2 cents per share for both periods);

• decreased property taxes at Ameren Missouri due to lower assessed property values (2 cents per share for both periods);

• increased Ameren Illinois Natural Gas earnings from investments in qualifying infrastructure recovered under the QIP rider (1 cent per share and 2 cents per share, respectively);

• increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base investment (1 cent per share and 2 cents per share, respectively); and

• the recognition of a MEEIA 2016 performance incentive (2 cents per share for the six months ended June 30, 2018).

Earnings per diluted share were unfavorably affected in the three and six months ended June 30, 2018, compared to the year-ago periods (except where a specific period is referenced), by:

• increased other operation and maintenance expenses not subject to riders or regulatory tracking mechanisms, primarily at Ameren Missouri (5 cents per share and 8 cents per share, respectively);

• decreased earnings at Ameren Missouri and Ameren Illinois Natural Gas, primarily due to timing differences between the recognition of revenue and income tax expense (3 cents per share and 4 cents per share, respectively);

• increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms, primarily at Ameren Missouri, resulting from additional electric property, plant, and equipment (2 cents per share and 4 cents per share, respectively); and

• an increase in weighted-average diluted shares outstanding (1 cent per share for both periods).

The cents per share information presented is based on the weighted-average basic shares outstanding in the three and six months ended 2017, and does not reflect any change in earnings per share resulting from dilution unless otherwise noted. Amounts other than variances related to income taxes have been presented net of income taxes using Ameren’s 2018 statutory tax rate of 27%. For additional

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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, Net, 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 and six months ended June 30, 2018 and 2017:

	Ameren Missouri			Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas			Ameren Transmission			Other / Intersegment Eliminations			Total
Three Months 2018:
Electric margins	$	704		$	269		$	—		$	103		$	(8	)	$	1,068
Natural gas margins	17			—			99			—			—			116
Other operations and maintenance	(241		)	(129		)	(54		)	(16		)	1			(439		)
Depreciation and amortization	(138		)	(65		)	(17		)	(19		)	1			(238		)
Taxes other than income taxes	(84		)	(21		)	(13		)	(3		)	(1		)	(122		)
Other income, net	16			8			4			1			—			29
Interest charges	(51		)	(19		)	(9		)	(18		)	(3		)	(100		)
Income (taxes) benefit	(54		)	(10		)	(2		)	(12		)	4			(74		)
Net income (loss)	169			33			8			36			(6		)	240
Noncontrolling interests – preferred stock dividends	(1		)	—			(1		)	—			1			(1		)
Net income (loss) attributable to Ameren common shareholders	$	168		$	33		$	7		$	36		$	(5	)	$	239
Three Months 2017:
Electric margins	$	654		$	290		$	—		$	105		$	(6	)	$	1,043
Natural gas margins	17			—			98			—			(1		)	114
Other operations and maintenance	(224		)	(143		)	(55		)	(15		)	6			(431		)
Depreciation and amortization	(132		)	(59		)	(15		)	(15		)	(1		)	(222		)
Taxes other than income taxes	(85		)	(18		)	(10		)	(2		)	(2		)	(117		)
Other income, net	16			3			—			—			1			20
Interest charges	(53		)	(19		)	(8		)	(16		)	(3		)	(99		)
Income (taxes) benefit	(72		)	(21		)	(4		)	(23		)	6			(114		)
Net income	121			33			6			34			—			194
Noncontrolling interests – preferred stock dividends	(1		)	—			(1		)	—			1			(1		)
Net income attributable to Ameren common shareholders	$	120		$	33		$	5		$	34		$	1		$	193
Six Months 2018:
Electric margins	$	1,215		$	532		$	—		$	207		$	(14	)	$	1,940
Natural gas margins	44			—			263			—			—			307
Other operations and maintenance	(473		)	(254		)	(114		)	(32		)	3			(870		)
Depreciation and amortization	(274		)	(128		)	(32		)	(37		)	(1		)	(472		)
Taxes other than income taxes	(164		)	(38		)	(36		)	(4		)	(5		)	(247		)
Other income, net	29			11			5			3			4			52
Interest charges	(102		)	(37		)	(19		)	(37		)	(6		)	(201		)
Income (taxes) benefit	(67		)	(19		)	(17		)	(27		)	14			(116		)
Net income (loss)	208			67			50			73			(5		)	393
Noncontrolling interests – preferred stock dividends	(2		)	(1		)	(1		)	—			1			(3		)
Net income (loss) attributable to Ameren common shareholders	$	206		$	66		$	49		$	73		$	(4	)	$	390
Six Months 2017:
Electric margins	$	1,104		$	568		$	—		$	207		$	(15	)	$	1,864
Natural gas margins	41			—			252			—			(1		)	292
Other operations and maintenance	(443		)	(276		)	(109		)	(31		)	10			(849		)
Depreciation and amortization	(265		)	(118		)	(29		)	(29		)	(2		)	(443		)
Taxes other than income taxes	(160		)	(36		)	(31		)	(3		)	(5		)	(235		)
Other income (expense), net	32			4			(1		)	—			3			38
Interest charges	(107		)	(37		)	(18		)	(31		)	(5		)	(198		)
Income (taxes) benefit	(75		)	(41		)	(25		)	(45		)	15			(171		)
Net income	127			64			39			68			—			298
Noncontrolling interests – preferred stock dividends	(2		)	(1		)	(1		)	—			1			(3		)
Net income attributable to Ameren common shareholders	$	125		$	63		$	38		$	68		$	1		$	295

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Below is Ameren Illinois' table of income statement components by segment for the three and six months ended June 30, 2018 and 2017:

	Ameren Illinois Electric Distribution			Ameren Illinois  Natural Gas			Ameren Illinois Transmission			Total
Three Months 2018:
Electric and natural gas margins	$	269		$	99		$	62		$	430
Other operations and maintenance	(129		)	(54		)	(13		)	(196		)
Depreciation and amortization	(65		)	(17		)	(12		)	(94		)
Taxes other than income taxes	(21		)	(13		)	(1		)	(35		)
Other income, net	8			4			1			13
Interest charges	(19		)	(9		)	(9		)	(37		)
Income taxes	(10		)	(2		)	(6		)	(18		)
Net income	33			8			22			63
Preferred stock dividends	—			(1		)	—			(1		)
Net income attributable to common shareholder	$	33		$	7		$	22		$	62
Three Months 2017:
Electric and natural gas margins	$	290		$	98		$	65		$	453
Other operations and maintenance	(143		)	(55		)	(14		)	(212		)
Depreciation and amortization	(59		)	(15		)	(11		)	(85		)
Taxes other than income taxes	(18		)	(10		)	—			(28		)
Other income, net	3			—			—			3
Interest charges	(19		)	(8		)	(9		)	(36		)
Income taxes	(21		)	(4		)	(12		)	(37		)
Net income	33			6			19			58
Preferred stock dividends	—			(1		)	—			(1		)
Net income attributable to common shareholder	$	33		$	5		$	19		$	57
Six Months 2018:
Electric and natural gas margins	$	532		$	263		$	124		$	919
Other operations and maintenance	(254		)	(114		)	(27		)	(395		)
Depreciation and amortization	(128		)	(32		)	(24		)	(184		)
Taxes other than income taxes	(38		)	(36		)	(2		)	(76		)
Other income, net	11			5			3			19
Interest charges	(37		)	(19		)	(18		)	(74		)
Income taxes	(19		)	(17		)	(14		)	(50		)
Net income	67			50			42			159
Preferred stock dividends	(1		)	(1		)	—			(2		)
Net income attributable to common shareholder	$	66		$	49		$	42		$	157
Six Months 2017:
Electric and natural gas margins	$	568		$	252		$	125		$	945
Other operations and maintenance	(276		)	(109		)	(27		)	(412		)
Depreciation and amortization	(118		)	(29		)	(21		)	(168		)
Taxes other than income taxes	(36		)	(31		)	(1		)	(68		)
Other income (expense), net	4			(1		)	—			3
Interest charges	(37		)	(18		)	(18		)	(73		)
Income taxes	(41		)	(25		)	(23		)	(89		)
Net income	64			39			35			138
Preferred stock dividends	(1		)	(1		)	—			(2		)
Net income attributable to common shareholder	$	63		$	38		$	35		$	136

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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 three and six months ended June 30, 2018, compared with the year-ago periods. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as 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.

Three Months	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)	$	69		$	—		$	—		$	—		$	—		$	69
Base rates (estimate)(c)	(37		)	(8		)	—			(2		)	—			(47		)
Recovery of power restoration efforts provided to other utilities	2			2			—			—			—			4
Sales volume (excluding the effect of weather)	16			—			—			—			—			16
Off-system sales	(54		)	—			—			—			—			(54		)
Energy-efficiency program investments	—			3			—			—			—			3
Other	9			1			—			—			—			10
Cost recovery mechanisms – offset in fuel and purchased power(d)	6			19			—			—			—			25
Other cost recovery mechanisms(e)	7			(19		)	—			—			—			(12		)
Total electric revenue change	$	18		$	(2	)	$	—		$	(2	)	$	—		$	14
Fuel and purchased power change:
Energy costs (excluding the effect of weather)	$	49		$	—		$	—		$	—		$	—		$	49
Effect of weather (estimate)(b)	(11		)	—			—			—			—			(11		)
Other	—			—			—			—			(2		)	(2		)
Cost recovery mechanisms – offset in electric revenue(d)	(6		)	(19		)	—			—			—			(25		)
Total fuel and purchased power change	$	32		$	(19	)	$	—		$	—		$	(2	)	$	11
Net change in electric margins	$	50		$	(21	)	$	—		$	(2	)	$	(2	)	$	25
Natural gas revenue change:
Effect of weather (estimate)(b)	$	7		$	—		$	—		$	—		$	—		$	7
Base rates (estimate)	—			—			(7		)	—			—			(7		)
QIP rider	—			—			6			—			—			6
Other	—			—			—			—			1			1
Cost recovery mechanisms – offset in natural gas purchased for resale(d)	(4		)	—			7			—			—			3
Other cost recovery mechanisms(e)	—			—			2			—			—			2
Total natural gas revenue change	$	3		$	—		$	8		$	—		$	1		$	12
Natural gas purchased for resale change:
Effect of weather (estimate)(b)	$	(7	)	$	—		$	—		$	—		$	—		$	(7	)
Cost recovery mechanisms – offset in natural gas revenue(d)	4			—			(7		)	—			—			(3		)
Total natural gas purchased for resale change	$	(3	)	$	—		$	(7	)	$	—		$	—		$	(10	)
Net change in natural gas margins	$	—		$	—		$	1		$	—		$	1		$	2

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Six Months	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)	$	120		$	—		$	—		$	—	$	—		$	120
Base rates (estimate)(c)	(32		)	(15		)	—			—		—			(47		)
Recovery of power restoration efforts provided to other utilities	12			10			—			—		—			22
Sales volume (excluding the effect of weather)	13			—			—			—		—			13
MEEIA 2016 performance incentive	5			—			—			—		—			5
Off-system sales	(123		)	—			—			—		—			(123		)
Energy-efficiency program investments	—			5			—			—		—			5
Other	—			2			—			—		5			7
Cost recovery mechanisms – offset in fuel and purchased power(d)	2			46			—			—		—			48
Other cost recovery mechanisms(e)	15			(35		)	—			—		—			(20		)
Total electric revenue change	$	12		$	13		$	—		$	—	$	5		$	30
Fuel and purchased power change:
Energy costs (excluding the effect of weather)	$	119		$	—		$	—		$	—	$	—		$	119
Effect of weather (estimate)(b)	(26		)	—			—			—		—			(26		)
Effect of lower net energy costs included in base rates	9			—			—			—		—			9
Other	(1		)	(3		)	—			—		(4		)	(8		)
Cost recovery mechanisms – offset in electric revenue(d)	(2		)	(46		)	—			—		—			(48		)
Total fuel and purchased power change	$	99		$	(49	)	$	—		$	—	$	(4	)	$	46
Net change in electric margins	$	111		$	(36	)	$	—		$	—	$	1		$	76
Natural gas revenue change:
Effect of weather (estimate)(b)	$	17		$	—		$	—		$	—	$	—		$	17
Base rates (estimate)	—			—			(10		)			—			(10		)
QIP rider	—			—			10			—		—			10
Other	—			—			2			—		1			3
Cost recovery mechanisms – offset in natural gas purchased for resale(d)	(8		)	—			44			—		—			36
Other cost recovery mechanisms(e)	1			—			9			—		—			10
Total natural gas revenue change	$	10		$	—		$	55		$	—	$	1		$	66
Natural gas purchased for resale change:
Effect of weather (estimate)(b)	$	(15	)	$	—		$	—		$	—	$	—		$	(15	)
Cost recovery mechanisms – offset in natural gas revenue(d)	8			—			(44		)	—		—			(36		)
Total natural gas purchased for resale change	$	(7	)	$	—		$	(44	)	$	—	$	—		$	(51	)
Net change in natural gas margins	$	3		$	—		$	11		$	—	$	1		$	15

(a) Includes a decrease in transmission margins of $3 million and $1 million for the three and six months ended June 30, 2018, respectively, compared with the year-ago periods, 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.

(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) Offsetting increases or decreases to expenses are reflected in “Operating Expenses – Other operations and maintenance” or in “Operating Expenses – Taxes other than income taxes” on the statement of income. These items have no overall impact on earnings.

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Ameren

Ameren’s electric margins increased $25 million, or 2%, and $76 million, or 4%, for the three and six months ended June 30, 2018, respectively, compared with the year-ago periods, primarily because of increased margins at Ameren Missouri, partially offset by decreased margins at Ameren Illinois Electric Distribution.

Ameren's natural gas margins increased $2 million, or 2%, and $15 million, or 5%, for the three and six months ended June 30, 2018, respectively, compared with the year-ago periods, primarily because of increased margins at Ameren Illinois Natural Gas.

Ameren Transmission

Ameren Transmission's margins were comparable for the three and six months ended June 30, 2018, compared with the year-ago periods. The reduction in the federal statutory corporate income tax rate decreased margins $14 million and $24 million, respectively, offset by increased other recoverable expenses and increased rate base under forward-looking formula ratemaking. See Note 2 – Rate and Regulatory Matters under Part I, Item 1 of this report for information regarding the reduction in the federal statutory corporate income tax rate.

Ameren Missouri

Ameren Missouri’s electric margins increased $50 million, or 8%, and $111 million, or 10%, for the three and six months ended June 30, 2018, respectively, compared with the year-ago periods. Ameren Missouri’s natural gas margins were comparable for the three months ended June 30, 2018, and increased $3 million, or 7%, for the six months ended June 30, 2018, compared with the year-ago periods, primarily due to colder winter temperatures, as discussed below.

The following items had a favorable effect on Ameren Missouri's electric margins for the three and six months ended June 30, 2018, compared with the year-ago periods (except where a specific period is referenced):

• Winter temperatures were colder as heating degree days increased 131% and 51% for the three and six months ended June 30, 2018, respectively, compared with the year-ago periods, and early summer temperatures were warmer as cooling degree days increased 22% for the three months ended June 30, 2018, compared with the year-ago period. The effect of weather increased margins an estimated $58 million and $94 million, respectively. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$69 million and +$120 million, respectively) and the effect of weather (estimate) on fuel and purchased power (-$11 million and -$26 million, respectively) in the table above.

• Excluding the estimated effects of weather and the MEEIA 2016 customer energy-efficiency programs, total retail sales volumes increased 3% and 2%, respectively, which increased margins an estimated $11 million and $9 million, respectively, primarily due to growth. The change in margins due to sales volumes is the sum of the effect of sales volumes (excluding the effect of weather) on electric revenues (+$16 million and +$13 million, respectively), the effect of the revenue change in off-system sales (-$54 millionand-$123 million, respectively) and the effect of the change in energy costs (excluding the effect of weather) (+$49 million and +$119 million, respectively) in the table above.

• The recovery of labor and benefit costs for crews assisting other utilities with power restoration efforts, which increased revenues $2 million and $12 million, respectively.

• The MEEIA 2016 performance incentive, which increased revenues $5 million for the six months ended June 30, 2018, compared with the year-ago period. See Note 2 – Rate and Regulatory Matters under Part I, Item 1 of this report for information regarding the MEEIA 2016 performance incentive.

Ameren Missouri's electric margins were unfavorably affected by decreased revenues, which reflected expected customer rate reductions in accordance with the TCJA section of Missouri Senate Bill 564, partially offset by higher electric base rates, as a result of the March 2017 electric rate order. These items collectively decreased margins an estimated $37 million and $23 million for the three and six months ended June 30, 2018, respectively, compared with the year-ago periods. The net change in electric base rates is the sum of the change in base rates (estimate) (-$37 million and -$32 million, respectively) and the effect of lower net energy costs included in base rates (+$9 million for the six months ended June 30, 2018) in the table above.

Ameren Illinois

Ameren Illinois' electric margins decreased $24 million, or 7%, and $37 million, or 5%, for the three and six months ended June 30, 2018, respectively, compared with the year-ago periods, driven by decreased margins at Ameren Illinois Electric Distribution. Ameren Illinois Natural Gas’ margins were comparable for the three months ended June 30, 2018, and increased $11 million, or 4%, for the six months ended June 30, 2018, compared with the year-ago periods.

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Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins decreased $21 million, or 7%, and $36 million, or 6%, for the three and six months ended June 30, 2018, respectively, compared with the year-ago periods.

The following items had an unfavorable effect on Ameren Illinois Electric Distribution’s margins for the three and six months ended June 30, 2018, compared with the year-ago periods:

• Revenues decreased $19 million and $35 million, respectively, primarily due to a decrease in recoverable customer energy-efficiency costs prior to the FEJA. See Other Operations and Maintenance Expenses in this section for the related offsetting decrease in customer energy-efficiency costs prior to the FEJA.

• Revenues decreased due to lower recoverable expenses under formula ratemaking pursuant to the IEIMA, partially offset by increased rate base, which collectively decreased margins $8 million and $15 million, respectively. The reduction in the federal statutory corporate income tax rate decreased recoverable expenses $15 million and $26 million, respectively.

The following items had a favorable effect on Ameren Illinois Electric Distribution’s margins for the three and six months ended June 30, 2018, compared with the year-ago periods:

• The recovery of labor and benefit costs for crews assisting other utilities with power restoration efforts, which increased revenues $2 million and $10 million, respectively.

• Revenues increased $3 million and $5 million, respectively, due to energy-efficiency program investments pursuant to the FEJA.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ margins were comparable for the three months ended June 30, 2018, and increased $11 million, or 4%, for the six months ended June 30, 2018, compared with the year-ago periods.

The following items had a favorable effect on Ameren Illinois Natural Gas’ margins for the three and six months ended June 30, 2018, compared with the year-ago periods:

• Revenues from QIP recoveries, which increased margins $6 million and $10 million, respectively, due to additional investment in qualified natural gas infrastructure.

• Revenues from other cost recovery mechanisms, which increased margins $2 million and $9 million, respectively.

Ameren Illinois Natural Gas’ margins were unfavorably affected by the reduction in the federal statutory corporate income tax rate, which decreased revenues $7 million and $10 million, respectively.

Ameren Illinois Transmission

Ameren Illinois Transmission’s margins were comparable for the three and six months ended June 30, 2018, compared with the year-ago periods. The reduction in the federal statutory corporate income tax rate decreased margins $9 million and $14 million, respectively, offset by increased rate base under forward-looking formula ratemaking.

Other Operations and Maintenance Expenses

Ameren

Other operations and maintenance expenses were $8 million and $21 million higher in the three and six months ended June 30, 2018, respectively, compared with the year-ago periods, as discussed below, as well as increases of $5 million and $7 million, respectively, for activity not reported as part of a segment, primarily due to a decrease in intersegment eliminations.

Ameren Missouri

Other operations and maintenance expenses were $17 million and $30 million higher in the three and six months ended June 30, 2018, respectively, compared with the year-ago periods. The following items increased other operations and maintenance expenses for the three and six months ended June 30, 2018, compared with the year-ago periods:

• Energy center maintenance costs, excluding refueling and maintenance outages costs at the Callaway energy center, increased $10 million and $15 million, respectively, primarily due to higher-than-normal non-nuclear scheduled outage costs, and higher coal handling charges.

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• Labor and benefit costs increased $3 million and $9 million, respectively, primarily due to assistance provided to other utilities to aid in power restoration efforts.

• MEEIA customer energy-efficiency program costs increased $2 million and $7 million, respectively.

Ameren Illinois

Other operations and maintenance expenses were $16 million and $17 million lower in the three and six months ended June 30, 2018, respectively, compared with the year-ago periods at Ameren Illinois, as discussed below. Other operations and maintenance expenses were comparable in the three and six months ended June 30, 2018, with the year-ago periods at Ameren Illinois Transmission.

Ameren Illinois Electric Distribution

Other operations and maintenance expenses decreased $14 million and $22 million in the three and six months ended June 30, 2018, respectively, compared with the year-ago periods, primarily because of a decrease of $19 million and $36 million, respectively, in customer energy-efficiency costs prior to the FEJA. This decrease was partially offset by a $5 million and $14 million increase in labor and benefit costs in the three and six months ended June 30, 2018, respectively, primarily due to assistance provided to other utilities to aid in power restoration efforts.

Ameren Illinois Natural Gas

Other operations and maintenance expenses were comparable in the three months ended June 30, 2018, and increased $5 million in the six months ended June 30, 2018, compared with the year-ago periods, primarily because of increased bad debt, customer energy-efficiency, and environmental remediation costs.

Depreciation and Amortization

Depreciation and amortization expenses increased $16 million, $6 million, and $9 million in the three months ended June 30, 2018, and $29 million, $9 million, and $16 million in the six months ended June 30, 2018, compared with the year-ago periods, at Ameren, Ameren Missouri, and Ameren Illinois, respectively, primarily because of additional property, plant, and equipment investments across their respective segments.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $5 million at Ameren in the three months ended June 30, 2018, compared with the year-ago period, primarily because of higher property taxes at Ameren Illinois Electric Distribution and higher gross receipts taxes at Ameren Illinois Natural Gas. Taxes other than income taxes increased $12 million at Ameren in the six months ended June 30, 2018, compared with the year-ago period, primarily because of higher gross receipts taxes at Ameren Missouri and Ameren Illinois Natural Gas. The increase in gross receipts taxes at Ameren Missouri in the six months ended June 30, 2018, is partially offset by a decrease in property taxes due to lower assessed property values.

Other Income, Net

Ameren

Other income, net, increased $9 million and $14 million in the three and six months ended June 30, 2018, compared with the year-ago periods, as discussed below. See Note 5 – Other Income, Net under Part I, Item 1, of this report for additional information.

Ameren Transmission

Other income, net, was comparable in the three months ended June 30, 2018, and increased $3 million in the six months ended June 30, 2018, compared with the year-ago periods, primarily because of an increase in the allowance for equity funds used during construction, along with an increase in the non-service cost components of net periodic benefit income resulting from the adoption of authoritative accounting guidance related to net periodic pension and postretirement benefit cost. See Note 11 – Retirement Benefits under Part I, Item 1, of this report for the non-service cost components of net periodic benefit income.

Ameren Missouri

Other income, net, was comparable in the three months ended June 30, 2018, and decreased $3 million in the six months ended June 30, 2018, compared with the year-ago periods, primarily because of a decrease in the non-service cost components of net periodic benefit income. See Note 11 – Retirement Benefits under Part I, Item 1, of this report for the non-service cost components of net periodic benefit income.

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Ameren Illinois

Other income, net, increased $10 million and $16 million in the three and six months ended June 30, 2018, compared with the year-ago periods, primarily because of an increase in the non-service cost components of net periodic benefit income at each Ameren Illinois segment. See Note 11 – Retirement Benefits under Part I, Item 1, of this report for the non-service cost components of net periodic benefit income.

Interest Charges

Ameren

Interest charges were comparable in the three months ended June 30, 2018, with the year-ago period at Ameren and each of its segments. Interest charges increased $3 million in the six months ended June 30, 2018, compared with the year-ago period, as discussed below.

Ameren Transmission

Interest charges increased $6 million in the six months ended June 30, 2018, compared with the year-ago period, primarily because of an increase in average outstanding debt at ATXI.

Ameren Missouri

Interest charges decreased $5 million in the six months ended June 30, 2018, primarily because of a decrease in the average interest rate of long-term debt.

Income Taxes

The following table presents effective income tax rates for the three and six months ended June 30, 2018 and 2017:

	Three Months(a)				Six Months(a)
	2018		2017		2018		2017
Ameren	24	%	37	%	23	%	36	%
Ameren Missouri	24	%	37	%	24	%	37	%
Ameren Illinois	23	%	39	%	24	%	39	%
Ameren Illinois Electric Distribution	22	%	39	%	22	%	39	%
Ameren Illinois Natural Gas	25	%	39	%	26	%	39	%
Ameren Illinois Transmission	22	%	39	%	25	%	39	%
Ameren Transmission	25	%	40	%	27	%	40	%

(a) Estimate of the annual effective income tax rate adjusted to reflect the tax effect of items discrete to the three and six months ended June 30, 2018 and 2017.

Ameren

The effective income tax rate was lower in the three and six months ended June 30, 2018, compared with the year-ago periods, because of the decrease in the federal statutory corporate income tax rate, along with amortization of excess deferred taxes at Ameren Illinois Electric Distribution, Ameren Illinois Transmission and Ameren Illinois Natural Gas and higher benefits related to stock-based compensation in the current year, partially offset by the higher statutory corporate income tax rate in Illinois in the current year.

Ameren Transmission

The effective income tax rate was lower in the three and six months ended June 30, 2018, compared with the year-ago periods, primarily because of the decrease in the federal statutory corporate income tax rate and amortization of excess deferred taxes in the current year, partially offset by the higher statutory corporate income tax rate in Illinois in the current year.

Ameren Missouri

The effective income tax rate was lower in the three and six months ended June 30, 2018, compared with the year-ago periods, primarily because of the decrease in the federal statutory corporate income tax rate in the current year. Based on an order issued by the MoPSC in July 2018, Ameren Missouri began amortizing excess deferred taxes in August 2018.

Ameren Illinois

The effective income tax rate was lower in the three and six months ended June 30, 2018, compared with the year-ago periods at Ameren Illinois and each of its segments primarily because of the decrease in the federal statutory corporate income tax rate in the current

54

year, partially offset by the higher statutory corporate income tax rate in Illinois in the current year. The amortization of excess deferred taxes at Ameren Illinois Electric Distribution and Ameren Illinois Transmission in the current year also contributed to the lower effective tax rate.

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, and/or, in the case of Ameren Missouri and Ameren Illinois, short-term intercompany borrowings to support 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).The TCJA benefits customers through lower rates for our services, but is not expected to materially affect our earnings. However, we expect our cash flows and rate base to be materially affected in the near term. The TCJA eliminated 50% accelerated tax depreciation on nearly all capital investments, which had the effect of increasing Ameren’s near-term projected income tax liabilities. Ameren expects to largely offset its income tax obligations through about 2020 with existing net operating loss and tax credit carryforwards. Since we had been using existing net operating loss and tax credit carryforwards to largely offset income tax obligations before the enactment of the TCJA, the effect of the reduced federal statutory corporate income tax rate is expected to decrease operating cash flows. The decrease in operating cash flows will be further reduced by lower customer rates, reflecting the return of excess deferred taxes previously collected from customers over periods of time determined by our regulators. The decrease in operating cash flows as a result of the TCJA is expected to be partially offset over time by increased customer rates due to higher rate base amounts, once approved by our regulators. We expect rate base amounts to be higher as a result of lower accumulated deferred income tax liabilities, due to the elimination of 50% accelerated tax depreciation, the reduced statutory income tax rate, and the return of excess deferred taxes to customers. We also 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, grid modernization, environmental compliance, and other improvements. As part of its plan to fund these cash flow requirements, beginning in the first quarter of 2018, Ameren began to use newly issued shares, rather than market-purchased shares, to satisfy requirements under its DRPlus and employee benefit plans and expects to continue to do so over the next five years. Additionally, we may need to issue incremental debt and/or equity, with the long-term intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking 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 June 30, 2018, for the Ameren Companies. The working capital deficit as of June 30, 2018, was primarily the result of current maturities of long-term debt as well as commercial paper issuances at Ameren (parent). With the credit capacity available under the Credit Agreements, the Ameren Companies had access to $1.6 billion of liquidity atJune 30, 2018.

The following table presents net cash provided by (used in) operating, investing, and financing activities for the six months ended June 30, 2018 and 2017:

	Net Cash Provided By Operating Activities							Net Cash Used In Investing Activities									Net Cash Provided by (Used In) Financing Activities
	2018		2017		Variance			2018			2017			Variance			2018		2017			Variance
Ameren(a)	$	820	$	863	$	(43	)	$	(1,129	)	$	(1,059	)	$	(70	)	$	337	$	197		$	140
Ameren Missouri	412		396		16			(543		)	(253		)	(290		)	149		(143		)	292
Ameren Illinois	287		375		(88		)	(599		)	(480		)	(119		)	328		105			223

(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 regulatory rate review. 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$43 million in the first six months of 2018, compared with the year-ago period. The following items contributed to the decrease:

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• A $31 million decrease due to the purchase of zero emission credits pursuant to a January 2018 IPA procurement event primarily with funds previously collected from Ameren Illinois customers.

• A $25 million increase in expenditures for customer energy-efficiency programs at Ameren Illinois compared with amounts collected from customers under a cost recovery mechanism.

• A $20 million decrease related to Ameren Illinois’ IEIMA revenue requirement reconciliation adjustments. The 2016 revenue requirement reconciliation adjustment, which was recovered from customers in 2018, was less than the 2015 revenue requirement reconciliation adjustment, which was recovered from customers in 2017.

• A $19 million decrease in net energy costs collected from Ameren Missouri customers under the FAC.

• An $18 million decrease resulting from income tax payments of $6 million, compared with income tax refunds of $12 million in 2017, pursuant to the tax allocation agreement with Ameren (parent), primarily due to the timing of payments and decreased tax due to the lower federal income tax rate and lower property-related deductions.

• A $13 million increase in energy center maintenance costs at Ameren Missouri, excluding refueling and maintenance outage costs at the Callaway energy center, primarily due to higher-than-normal, non-nuclear scheduled outage costs, in addition to higher coal handling charges.

• A net $11 million decrease in returns of collateral posted with counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes.

• A $9 million decrease in transmission service costs collected from Ameren Illinois customers under a cost recovery mechanism.

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

• A $27 million increase in natural gas commodity costs collected from Ameren Missouri and Ameren Illinois customers under the PGA.

• The absence of $21 million in refunds paid in 2017 associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K.

• An $18 million increase in renewable energy credit compliance costs collected from Ameren Illinois customers pursuant to the FEJA.

• A $17 million decrease in the cost of natural gas held in storage at Ameren Illinois, caused primarily by increased withdrawals as a result of colder winter temperatures compared with the prior year.

• A $14 million decrease in pension and postretirement benefit contributions.

• A $14 million decrease in expenditures for customer energy efficiency programs at Ameren Missouri compared with amounts collected from customers under MEEIA.

• A $9 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.

• A $6 million decrease in coal inventory at Ameren Missouri because of decreased market prices.

Ameren Missouri

Ameren Missouri’s cash from operating activities increased$16 million in the first six months of 2018, compared with the year-ago period. The following items contributed to the increase:

• A $49 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.

• A $14 million decrease in expenditures for customer energy-efficiency programs at Ameren Missouri compared with amounts collected from customers under MEEIA.

• A $12 million increase in natural gas commodity costs collected from customers under the PGA.

• A $7 million increase in interest payments, primarily due to a decrease in the average interest rate of long-term debt.

• A $6 million decrease in coal inventory because of decreased market prices.

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

• A $19 million decrease in net energy costs collected from customers under the FAC.

• A $13 million increase in energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center, primarily due to higher-than-normal non-nuclear scheduled outage costs, in addition to higher coal handling charges.

• An increase in income tax payments of $11 million to Ameren (parent) pursuant to the tax allocation agreement, primarily related to the timing of payments and decreased tax due to the lower federal income tax rate and lower property-related deductions.

• A net $10 million decrease in returns of collateral posted with counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes.

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Ameren Illinois

Ameren Illinois’ cash from operating activities decreased$88 million in the first six months of 2018, compared with the year-ago period. The following items contributed to the decrease:

• A $39 million decrease resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.

• A $31 million decrease due to the purchase of zero emission credits pursuant to a January 2018 IPA procurement event primarily with funds previously collected from customers.

• A $25 million increase in expenditures for customer energy-efficiency programs compared with amounts collected from customers.

• A $21 million increase in income tax payments to Ameren (parent) pursuant to the tax allocation agreement resulting primarily from the timing of payments and lower property-related deductions, partially offset by decreased tax due to the lower federal income tax rate.

• A $20 million decrease related to IEIMA revenue requirement reconciliation adjustments. The 2016 revenue requirement reconciliation adjustment, which was recovered from customers in 2018, was less than the 2015 revenue requirement reconciliation adjustment, which was recovered from customers in 2017.

• A $9 million decrease in transmission service costs collected from Ameren Illinois customers under a cost recovery mechanism.

• An $8 million decrease related to the timing of payments from affiliates.

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

• An $18 million increase in renewable energy credit compliance costs collected from customers pursuant to the FEJA.

• The absence of $17 million in refunds paid in 2017 associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K.

• A $16 million decrease in the cost of natural gas held in storage caused primarily by increased withdrawals as a result of colder winter temperatures compared with the prior year.

• A $15 million increase in natural gas commodity costs collected from customers under the PGA.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities increased by $70 million in the first six months of 2018, compared to the year-ago period, primarily as a result of increased capital expenditures of $114 million, partially offset by a decrease of $34 million due to the timing of nuclear fuel expenditures. Increased capital expenditures at Ameren Missouri and Ameren Illinois, discussed below, were partially offset by a $104 million decrease in capital expenditures at ATXI. ATXI’s capital expenditures decreased as a result of decreased expenditures on the Illinois Rivers and Spoon River projects. The Spoon River project was placed in service in February 2018.

Ameren Missouri’s cash used in investing activities increased by $290 million between periods, primarily due to net money pool advances. In the first six months of 2018, Ameren Missouri made $66 million in advances to the money pool, compared with $161 million in returns of net money pool advances received during the same period in 2017. Additionally, capital expenditures increased $99 million between periods primarily related to energy center projects and electric distribution system reliability projects. The increase in capital expenditures was partially offset by a $34 million decrease in nuclear fuel expenditures due to the timing of purchases.

Ameren Illinois’ cash used in investing activities increased by $119 million between periods due to an increase in capital expenditures of $118 million primarily related to substation upgrades, upgrades to natural gas main infrastructure, and electric transmission system reliability projects.

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 level of dividends, and our long-term debt maturities, among other things.

Ameren’s cash provided by financing activities increased by $140 million during the first six months of 2018, compared to the year-ago period. During the first six months of 2018, Ameren utilized net proceeds from the issuance of $874 million of long-term indebtedness and net commercial paper issuances to repay $323 million of higher-cost long-term indebtedness and to fund, in part, investing activities. In comparison, during the first six months of 2017, Ameren utilized net proceeds from the issuance of $883 million of long-term indebtedness and net commercial paper issuances to repay $425 million of higher-cost long-term indebtedness and to fund, in part, investing activities. Additionally, Ameren issued $40 million in common stock under its DRPlus and 401(k) plan in the first six months of 2018. Ameren also issued common stock related to stock-based compensation resulting in noncash financing activity during the first six months of 2018, compared with $24 million paid for the repurchase of common stock for stock-based compensation in the year-ago period. Ameren did not issue common stock in the first six months of 2017.

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Ameren Missouri’s financing activities provided cash of $149 million during the first six months of 2018, compared to using cash of $143 million during the same period in 2017. During the first six months of 2018, Ameren Missouri utilized net proceeds from the issuance of $423 million of long-term indebtedness to repay $179 million of higher-cost long-term indebtedness, to repay $39 million of net commercial paper issuances, and to fund, in part, investing activities. In comparison, during the first six months of 2017, Ameren Missouri utilized net proceeds from the issuance of $459 million of long-term indebtedness and net commercial paper issuances to repay $425 million of higher-cost long-term indebtedness and to fund, in part, investing activities. Additionally, during the first six months of 2018, Ameren Missouri paid $50 million in common stock dividends, compared with $172 million in dividend payments in the year-ago period.

Ameren Illinois’ cash provided by financing activities increased by $223 million during the first six months of 2018, compared to the year-ago period. During the first six months of 2018, Ameren Illinois utilized net proceeds from the issuance of $430 million of long-term indebtedness to repay $62 million of net commercial paper issuances, and to fund, in part, investing activities. During the first six months of 2018, Ameren Illinois used commercial paper issuances to repay $144 million of higher-cost long-term indebtedness. In comparison, during the first six months of 2017, Ameren Illinois utilized net proceeds from commercial paper issuances of $108 million to fund, in part, investing activities. Additionally, in the first six months of 2018, Ameren Illinois received an $80 million capital contribution from Ameren (parent) and borrowed $31 million from the money pool, compared with no capital contribution or money pool activity in the year-ago period.

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

Credit Facility Borrowings and Liquidity

The liquidity needs of Ameren, Ameren Missouri, and Ameren Illinois are typically supported through the use of available cash, or proceeds from short-term affiliate borrowings, borrowings under the Credit Agreements, or commercial paper issuances. See Note 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information on credit agreements, commercial paper issuances, borrowings under Ameren’s money pool arrangements, and relevant interest rates.

The following table presents Ameren’s consolidated liquidity as of June 30, 2018:

Ameren (parent)and Ameren Missouri:
Missouri Credit Agreement – borrowing capacity	$	1,000
Less: Ameren (parent) commercial paper outstanding	295
Missouri Credit Agreement – credit available	705
Ameren (parent) and Ameren Illinois:
Illinois Credit Agreement – borrowing capacity	1,100
Less: Ameren (parent) commercial paper outstanding	211
Less: Letters of credit	1
Illinois Credit Agreement – credit available	888
Total Credit Available	$	1,593
Cash and cash equivalents	29
Total Liquidity	$	1,622

The Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs. Both of the Credit Agreements are available to Ameren (parent) to support issuances under Ameren (parents)’s commercial paper program, subject to available credit capacity under the agreements. 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 of borrowings 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 has the lowest interest rates.

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by the FERC under the Federal Power Act. In March 2018, the FERC issued an order authorizing Ameren Missouri to issue up to $1.0 billion of short-term debt securities through March 2020.

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

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Long-term Debt and Equity

The following table presents Ameren’s equity issuances, as well as issuances (net of any issuance premiums or discounts), redemptions, repurchases, and maturities of long-term debt for Ameren Missouri, Ameren Illinois, and ATXI for the six months ended June 30, 2018 and 2017.

	Month Issued, Redeemed, or Matured	2018			2017
Issuances of Long-term Debt
Ameren Missouri:
4.00% First mortgage bonds due 2048	April	$	423		$	—
2.95% Senior secured notes due 2027	June	—			399
Ameren Illinois:
3.80% First mortgage bonds due 2028	May	430			—
ATXI:
3.43% Senior notes due 2050	June	—			150
Total Ameren long-term debt issuances		$	853		$	549
Issuances of Common Stock
Ameren:
DRPlus and 401(k)	Various	$	40	(a) (b)	$	—
Total common stock issuances		$	40		$	—
Total Ameren long-term debt and common stock issuances		$	893		$	549
Redemptions and Maturities of Long-term Debt
Ameren Missouri:
6.00% Senior secured notes due 2018	April	$	179		$	—
6.40% Senior secured notes due 2017	June	—			425
Ameren Illinois:
6.25% Senior secured notes due 2018	May	144			—
Total Ameren long-term debt redemptions and maturities		$	323		$	425

(a) Ameren issued a total of 0.7 million shares of common stock under its DRPlus and 401(k) plan.

(b) Excludes 0.7 million shares of common stock valued at $35 million issued in connection with stock-based compensation.

See Note 4 – Long-Term Debt and Equity Financings under Part 1, Item 1, of this report for additional information, including proceeds from issuances of long-term debt and use of those proceeds.

Indebtedness Provisions and Other Covenants

See Note 3 – Short-term Debt and Liquidity 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 provisions (and applicable cross-default provisions) and covenants contained in our credit agreements, in ATXI’s note purchase agreement, and in certain of the Ameren Companies’ indentures and articles of incorporation.

At June 30, 2018, the Ameren Companies were in compliance with the provisions and covenants contained in their credit agreements, indentures, and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement.

We consider access to short-term and long-term capital markets to be a significant source of funding for capital requirements not satisfied by cash provided by our operating activities. Inability to raise capital on reasonable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing its current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri, and Ameren Illinois each believes that it will continue to have access to the capital markets. However, events beyond Ameren’s, Ameren Missouri’s, and Ameren Illinois’ control may create uncertainty in the capital markets or make access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.

Dividends

The amount and timing of dividends payable on Ameren’s common stock 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

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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 annual earnings over the next few years.

See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of the Form 10-K for additional discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At June 30, 2018, 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 subsidiaries to their parent, Ameren Corporation, for the six months ended June 30, 2018 and 2017:

	Six Months
	2018		2017
Ameren Missouri	$	50	$	172
Ameren Illinois	—		—
ATXI	25		—
Ameren	223		214

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 10 – Retirement Benefits under Part II, Item 8, of the Form 10-K for information regarding expected minimum funding levels for our pension plan.

At June 30, 2018, total obligations related to minimum purchase 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 $2,058 million, $1,227 million, and $779 million, respectively.

Off-balance-sheet Arrangements

At June 30, 2018, 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.

Credit Ratings

Our credit ratings affect our liquidity, our access to the capital markets and credit markets, our cost of borrowing under our credit facilities and our commercial paper programs, and our collateral posting requirements under commodity contracts.

The following table presents the principal credit ratings by Moody’s and S&P, as applicable, 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
ATXI:
Issuer credit rating	A2	Not Rated
Senior unsecured debt	A2	Not Rated

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A credit rating is not a recommendation to buy, sell, or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.

Collateral Postings

Any 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 June 30, 2018. A sub-investment-grade issuer or senior unsecured debt rating (whether below “BBB-” from S&P or below “Baa3” from Moody’s) at June 30, 2018, 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 $99 million, $52 million, and $47 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at June 30, 2018, if market prices were 15% higher or lower than June 30, 2018 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 seek to improve our regulatory frameworks and cost recovery mechanisms and are simultaneously pursuing constructive regulatory outcomes within existing frameworks, while also advocating for responsible energy policies. We align our overall spending, both operating and capital, with economic conditions and with the frameworks established by our regulators and to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We focus on minimizing the gap between allowed and earned returns on equity and allocating capital resources to business opportunities that we expect will offer the most attractive risk-adjusted return potential.

As part of Ameren’s strategic plan, we pursue projects to meet our customers’ energy needs and to improve electric and natural gas system reliability, safety, and security within our service territories. Ameren also evaluates competitive electric transmission investment opportunities as they arise. Additionally, Ameren Missouri expects to make investments over time that will enable it to transition to a more diverse energy generation portfolio, including investments in renewable energy resources.

Below are some key trends, events, and uncertainties that may reasonably affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 2018 and beyond.

Operations

• On June 1, 2018, Missouri Senate Bill 564 was enacted. The section of the law applicable to the TCJA became effective immediately; the remaining sections, including the ability to elect PISA, become effective August 28, 2018.The law required the MoPSC to authorize a reduction in Ameren Missouri’s rates to pass through the effect of the TCJA within 90 days of the law’s effective date. In July 2018, the MoPSC authorized Ameren Missouri to reduce its annual revenue requirement by $167 million and reflect that reduction in rates beginning August 1, 2018.In addition, Ameren Missouri recorded a reduction to revenue and a corresponding regulatory liability of $47 million for the excess amounts collected in rates related to the TCJA from January 1, 2018, through June 30, 2018. An additional amount will be recorded for July 2018 revenues. The regulatory liability will be reflected in customer rates over a period of time to be determined by the MoPSC in the next regulatory rate review.Upon Ameren Missouri’s expected PISA election, it would be permitted to defer and recover 85% of the depreciation expense and return on rate base on certain property, plant, and equipment placed in-service after August 28, 2018, and not included in base rates, which would mitigate the impacts of regulatory lag between regulatory rate reviews. Upon approval in a regulatory rate review, PISA deferrals would be added to rate base prospectively and earn a return based on Ameren Missouri’s weighted-average cost of capital over a recovery period of 20 years. Additional provisions apply when electing the use of PISA, including limiting customer rate increases to a 2.85% compound annual growth rate in the average overall customer rate per kilowatthour, applied to electric rates established April 1, 2017, less half of the 2018 savings from the TCJA passed on to customers. Ameren Missouri's electric base rates would also be frozen until April 2020 if the use of PISA is elected. Both the rate cap and PISA election would be effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028. Ameren Missouri’s expected PISA election will support Ameren Missouri's ability to invest approximately $1 billion of incremental capital over the 2019 to 2023 period to strengthen and modernize Missouri's electric grid. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information.

• In June 2018, the MoPSC approved Ameren Missouri’s Renewable Choice Program, which allows large commercial and industrial customers and municipalities to receive up to 100 percent of their energy from renewable resources. The tariff-based program is designed to recover the costs of the election, net of changes in the market price of such energy. Based on customer contracts, the program enables Ameren Missouri to supply up to 400 megawatts of renewable wind energy generation, up to 200 megawatts of which it

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could own. As applicable, the addition of generation by Ameren Missouri would be subject to the issuance of a certificate of convenience and necessity by the MoPSC, obtaining transmission interconnection agreements with the MISO or other RTOs, and approval by the FERC. This generation would be incremental to the expected renewable generation included in the 2017 IRP. Without extension, the option to elect into the program will terminate in the third quarter of 2023.

• Ameren continues to invest in FERC-regulated electric transmission. ATXI has three MISO-approved multi-value projects: the Spoon River, Illinois Rivers, and Mark Twain projects. The Spoon River project, located in northwest Illinois, was placed in service in February 2018. The Illinois Rivers project involves the construction of a transmission line from eastern Missouri across Illinois to western Indiana. Construction activities for the Illinois Rivers project are continuing on schedule, and the last section of this project is expected to be completed by the end of 2019. The Mark Twain project involves the construction of a transmission line from northeast Missouri, connecting the Illinois Rivers project to Iowa. Construction activities for the Mark Twain project are continuing on schedule and are expected to be completed by the end of 2019. ATXI’s expected remaining investment in its multi-value projects is approximately $300 million from 2018 through 2019, with the total investment to be more than $1.6 billion. In addition, Ameren Illinois expects to invest $2.3 billion in electric transmission assets from 2018 through 2022, to replace aging infrastructure and improve reliability.

• 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 expected rate base growth and the currently allowed 10.82% return on common equity, the 2018 revenue requirements included in rates for Ameren Illinois’ and ATXI’s electric transmission businesses are $273 million and $174 million, respectively. These revenue requirements represent an increase in Ameren Illinois' and ATXI's revenue requirements of $12 million and $3 million, respectively, primarily because of the rate base growth, partially offset by a decrease due to the lower federal statutory corporate income tax rates enacted under the TCJA.

• The return on common equity for MISO transmission owners, including Ameren Illinois and ATXI, is the subject of a FERC complaint case filed in February 2015 challenging the allowed base return on common equity. Ameren Illinois and ATXI currently use the FERC authorized total allowed return on common equity of 10.82% in customer rates. A final FERC order would establish the allowed return on common equity to be applied to the 15-month period from February 2015 to May 2016 and also establish the return on common equity to be included in customer rates prospectively from the effective date of such order, replacing the current 10.82% total return on common equity. The timing and amount of any adjustment to the total allowed return on common equity that may be ordered as a result of the complaint case is uncertain. 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 $8 million and $4 million, respectively, based on each company’s 2018 projected rate base.

• Illinois law provides for an annual reconciliation of the electric distribution service 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' 2018 electric distribution service revenues will 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. The 2018 revenue requirement is expected to be comparable to the 2017 revenue requirement because of an expected increase in recoverable costs, expected rate base growth, and an expected increase in the monthly average yield of 30-year United States Treasury bonds, partially offset by a decrease due to the lower federal statutory corporate income tax rates enacted under the TCJA. The 2018 revenue requirement reconciliation is expected to result in a regulatory asset that will be collected from customers in 2020. A 50 basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $8 million change in Ameren’s and Ameren Illinois’ net income, based on Ameren Illinois’ 2018 projected year-end rate base.

• In April 2018, Ameren Illinois filed its annual electric distribution service formula rate update to establish the revenue requirement to be used for 2019 rates with the ICC. In July 2018, the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing, recommending an amount comparable to Ameren Illinois’ filing. Pending ICC approval, this update filing will result in a $72 millionincrease in Ameren Illinois’ electric distribution service rates beginning in January 2019. These rates will affect Ameren Illinois' cash receipts during 2019, but will not determine its electric distribution service operating revenues, which will instead be based on its 2019 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 2019 rates is expected by December 2018.

• Ameren Illinois is allowed to earn a return on its electric energy-efficiency program investments. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and 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 be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals. Pursuant to the FEJA, Ameren Illinois plans to invest up to $99 million per year in electric energy-efficiency programs from 2018 through 2021 that will earn a return. Ameren Illinois plans to make similar yearly investments in electric energy-efficiency programs from 2022 through 2030. The ICC has the ability to reduce electric energy-efficiency savings goals if there are insufficient cost-effective programs available or if the savings goals would require investment levels that

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exceed amounts allowed by legislation. The electric energy-efficiency program investments and the return on those investments are being collected from customers through a rider; they will not be included in the IEIMA formula ratemaking framework.

• In January 2018, Ameren Illinois filed a request with the ICC seeking approval to increase its annual rates for natural gas delivery service. In July 2018, Ameren Illinois and the ICC staff filed a stipulation and agreement with the ICC that, pending ICC approval, would result in an annual natural gas rate increase of $37 million, based on the terms of the agreement and subject to adjustments for updated rate case and other postretirement benefit expenses. This increase in annual rates includes a 9.87% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion. It also reflects the reduction in the federal corporate income tax rate as a result of the TCJA, as well as the increase in the Illinois corporate income tax rate that became effective in July 2017, which decreased the annual rates by approximately $17 million. In an attempt to reduce regulatory lag, Ameren Illinois used a 2019 future test year in this proceeding.

• Ameren Missouri’s next scheduled refueling and maintenance outage at its Callaway energy center is scheduled for the spring of 2019. During the 2017 refueling, Ameren Missouri incurred maintenance expenses of $35 million. During a refueling, 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. In addition, Ameren Missouri may incur increased nonnuclear energy center maintenance costs in non-refueling years.

• Ameren Missouri expects to realize lower costs of fuel for generation over the next few years, compared to current levels, resulting from anticipated or recently signed coal and related transportation contracts. Substantially all the benefit of these lower costs would be passed through to customers through the FAC.

• Ameren Missouri and Ameren Illinois continue to make infrastructure investments and expect to seek regular electric and natural gas rate increases to recover the cost of investments and earn an adequate return. Ameren Missouri and Ameren Illinois will also seek legislative solutions, as necessary, such as Missouri Senate Bill 564, 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, and increased customer use of increasingly cost-effective technological advances, including private generation and storage. However, over the long-term, we expect the decreased demand to be partially offset by increased demand resulting from increased electrification of the economy as a means to address CO₂ emission concerns. Increased investments, including expected future investments for environmental compliance, system reliability improvements, and potential new generation sources, result in rate base earnings growth but also higher depreciation and financing costs.

For additional information regarding recent rate orders, lawsuits, and pending requests filed with state and federal regulatory commissions, see Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report.

Liquidity and Capital Resources

• Ameren Missouri’s 2017 IRP targets cleaner and more diverse sources of energy generation, including solar, wind, natural gas, hydro, and nuclear power. It also includes expanding renewable sources by adding at least 700 megawatts of wind generation by 2020 in Missouri and neighboring states and adding 100 megawatts of solar generation over the next 10 years. These new renewable energy sources would support Ameren Missouri’s compliance with the state of Missouri’s requirement of achieving 15% of native load sales from renewable energy sources by 2021, subject to customer rate increase limitations. Based on current and projected market prices for energy and for wind and solar generation technologies, among other factors, Ameren Missouri expects its ownership of these renewable resources would represent the lowest-cost option for customers. The plan also provides for the expected implementation of continued customer energy-efficiency programs. Ameren Missouri’s plan for the addition of renewable resources could be affected by, among other factors: the availability of federal production and investment tax credits related to renewable energy and Ameren Missouri’s ability to use such credits; the cost of wind and solar generation technologies; energy prices; Ameren Missouri’s ability to obtain timely interconnection agreements with MISO or other RTOs, including the cost of such interconnections; and Ameren Missouri’s ability to obtain a certificate of convenience and necessity from the MoPSC for projects located in Missouri, and any other required project approvals.

• In connection with the 2017 IRP filing, Ameren Missouri established a goal of reducing CO₂ emissions 80% by 2050 from a 2005 base level. To meet this goal, Ameren Missouri is targeting a 35% CO₂ emission reduction by 2030 and a 50% reduction by 2040 from the 2005 level by retiring coal-fired generation at the end of each energy center’s useful life.

• In the second quarter of 2018, Ameren Missouri entered into an agreement with a subsidiary of Terra-Gen, LLC to acquire a 400-megawatt wind generation facility after construction. The facility is expected to be located in northeastern Missouri and to be completed

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in 2020. The acquisition is subject to certain conditions, including the issuance of a certificate of convenience and necessity by the MoPSC, obtaining a MISO transmission interconnection agreement, and approval by the FERC. Ameren Missouri has filed for the certificate of convenience and necessity with the MoPSC. This facility would help Ameren Missouri to comply with the state renewable energy standard.In addition, Ameren Missouri requested the MoPSC to authorize a proposed RESRAM that would allow Ameren Missouri to adjust customer rates, including recovery of interest at a short-term borrowing rate, on an annual basis without a traditional regulatory rate review. The RESRAM is designed to mitigate the impacts of regulatory lag for investments in wind generation and other renewables by providing more timely recovery of costs and would provide Ameren Missouri a greater opportunity to earn its allowed return on investment. Ameren Missouri anticipates a decision by January 2019 related to the certificate of convenience and necessity and proposed RESRAM.Further, Ameren Missouri is also pursuing the acquisition of an additional 300 megawatts of wind generation with multiple wind developers, which would allow Ameren Missouri to achieve compliance with Missouri's renewable energy standard.

• Through 2022, 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 up to $11.4 billion (Ameren Missouri - up to $4.5 billion; Ameren Illinois – up to $6.6 billion; ATXI – up to $0.3 billion) of capital expenditures during the period from 2018 through 2022. These estimates do not reflect the potential additional investments identified in Ameren Missouri’s 2017 IRP, which could represent incremental investments of approximately $1 billion through 2020 and are subject to regulatory approval. They also do not reflect potential incremental capital investments supported by newly enacted Missouri legislation of approximately $1 billion over the 2019 to 2023 period, nor do they reflect potential investments in new renewable sources of generation under Ameren Missouri's Renewable Choice Program.

• 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 or recommended for repeal 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, increased operating costs, or the closure or alteration 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 that 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.

• 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 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information regarding the Credit Agreements. By the end of 2019, $772 million and $312 million of senior secured notes are due to mature at 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 short-term debt with long-term debt in 2018 and 2019. 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.

• Federal income tax legislation enacted under the TCJA will have significant impacts on our results of operations, financial position, liquidity, and financial metrics. The TCJA benefits customers through lower rates for our services, but is not expected to materially affect our earnings. However, we expect our cash flows and rate base to be materially affected in the near term. Our rate-regulated businesses recover income taxes in customer rates based on the federal and state statutory corporate income tax rates in effect when the revenue requirements used to determine those rates were established. However, there is a timing difference between when we collect funds from our customers for income taxes and when we pay such taxes. The TCJA eliminated 50% accelerated tax depreciation on nearly all capital investments, which has the effect of increasing Ameren’s near-term projected income tax liabilities. Ameren expects to largely offset its income tax obligations through about 2020 with existing net operating loss and tax credit carryforwards. Since we had been using existing net operating loss and tax credit carryforwards to largely offset income tax obligations before the enactment of the TCJA, the effect of the reduced federal statutory corporate income tax rate is expected to decrease operating cash flows. The decrease in operating cash flows results from reduced customer rates, reflecting the tax rate decrease, without a corresponding reduction in income tax payments until about 2021. Additionally, operating cash flows will be further reduced by lower customer rates, reflecting the return of excess deferred taxes previously collected from customers over periods of time determined by our regulators. The decrease in operating cash flows as a result of the TCJA is expected to be partially offset over time by increased customer rates due to higher rate base amounts, once approved by our regulators. We expect rate base amounts to be higher as a result of lower accumulated deferred income tax liabilities, due to the elimination of 50% accelerated tax depreciation, the reduced statutory income tax rate, and the return of excess deferred taxes to customers.Ameren expects a decrease in operating cash flows of approximately $1 billion from 2018 through 2022 (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.4 billion) as a result of the TCJA, and expects an

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increase in rate base of approximately $1 billion over the same time period (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.5 billion). See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding the income tax proceedings with our regulators.

• As a result of the reduced federal statutory corporate income tax rate enacted under TCJA, at December 31, 2017, we recorded a reduction in certain deferred income tax liabilities and a corresponding increase to net regulatory liabilities for funds previously collected from customers to pay for those deferred income tax liabilities. The TCJA includes provisions related to the IRS normalization rules that address the time period over which certain plant-related components of the excess deferred income taxes are to be reflected in customer rates. This time period for the Ameren Companies and ATXI is approximately 35 to 60 years. Other components of the excess deferred income taxes are being reflected in customer rates over 7 to 10 years, with amortization periods subject to regulatory review at Ameren Illinois and ATXI. The following table presents the net regulatory liabilities associated with excess deferred income taxes as of December 31, 2017, and the related amortization periods:

Amortization Period	Ameren Missouri		Ameren Illinois			ATXI		Total
35 - 60 years	$	962	$	803		$	84	$	1,849	(a)
7 - 10 years	404		(3		)	2		403
Total	$	1,366	$	800		$	86	$	2,252

(a) The amortization period related to $130 million and $21 million at Ameren Illinois and ATXI, respectively, remains subject to regulatory rate review.

• In 2018, our rate-regulated businesses began to amortize excess deferred income taxes. Ameren Illinois and ATXI's 2018 income tax expense will reflect a full year of amortization, while Ameren Missouri's 2018 income tax expense will reflect five months of amortization related to its electric business, commencing in August 2018, in accordance with a MoPSC order received in July 2018. The amortization of such balances related to Ameren Missouri's gas business has not yet started. This amortization reduces our income tax expense and effective tax rates. Due to formula ratemaking, Ameren Illinois Electric Distribution and Ameren Transmission have an offsetting reduction in revenue from customers, with no overall impact on earnings. Ameren Missouri and Ameren Illinois Natural Gas interim period earnings may be affected by timing differences between the recognition of revenue and income tax expense. Based on its revenue pattern, Ameren Missouri anticipates a year-over-year increase in earnings in the third quarter of 2018, with the year-to-date third quarter increase in earnings to be largely offset in the fourth quarter of 2018, resulting in no material impact to year-over-year earnings.

• As of June 30, 2018, Ameren had $155 million in tax benefits from federal and state net operating loss carryforwards and $123 million in federal and state income tax credit carryforwards. These carryforwards are expected to partially offset income tax obligations until 2020, at which time Ameren expects to begin making material income tax payments. Consistent with the tax allocation agreement between Ameren (parent) and its subsidiaries, Ameren Missouri and Ameren Illinois are expected to make income tax payments to Ameren (parent) in 2018.

• In August 2018, the IRS proposed regulations that would clarify certain provisions of TCJA related to transition depreciation rules. We are currently assessing the potential impacts of the proposed regulations on our results of operations, financial position, and liquidity.

• Ameren expects its cash used for currently planned capital expenditures and dividends to exceed cash provided by operating activities over the next several years. As part of its plan to fund these cash requirements, beginning in the first quarter of 2018, Ameren began using newly issued shares, rather than market-purchased shares, to satisfy requirements under its DRPlus and employee benefit plans and expects to continue to do so over the next five years. Additionally, Ameren may need to issue incremental debt and/or equity, with the long-term intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks. Ameren Missouri and Ameren Illinois expect to fund cash flow needs through debt issuances, adjustments of dividends to Ameren (parent), and/or capital contributions from Ameren (parent), with the intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks.

The above items could have a material impact on our results of operations, financial position, and liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, and 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.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

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

There have been no material changes to the quantitative and qualitative disclosures about interest rate risk, credit risk, equity price risk, commodity price risk, and commodity supplier risk included in the Form 10-K. 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 and power, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three and six months ended June 30, 2018. We use various methods to determine the fair value of our contracts. In accordance with authoritative accounting guidance for fair value hierarchy levels, the sources we used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). See Note 7 – Fair Value Measurements under Part I, Item 1, of this report for additional information regarding the methods used to determine the fair value of these contracts.

	Three Months									Six Months
	Ameren Missouri			Ameren Illinois			Ameren			Ameren Missouri			Ameren Illinois			Ameren
Fair value of contracts at beginning of period, net	$	3		$	(219	)	$	(216	)	$	8		$	(217	)	$	(209	)
Contracts realized or otherwise settled during the period	(3		)	8			5			(7		)	14			7
Fair value of new contracts entered into during the period	7			—			7			8			(1		)	7
Other changes in fair value	3			(2		)	1			1			(9		)	(8		)
Fair value of contracts outstanding at end of period, net	$	10		$	(213	)	$	(203	)	$	10		$	(213	)	$	(203	)

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The following table presents maturities of derivative contracts as of June 30, 2018, 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	$	6		$	2		$	—		$	—		$	8
Level 2(a)	(4		)	(3		)	—			—			(7		)
Level 3(b)	7			2			—			—			9
Total	$	9		$	1		$	—		$	—		$	10
Ameren Illinois:
Level 1	$	—		$	(1	)	$	—		$	—		$	(1	)
Level 2(a)	(8		)	(9		)	(1		)	—			(18		)
Level 3(b)	(16		)	(30		)	(30		)	(118		)	(194		)
Total	$	(24	)	$	(40	)	$	(31	)	$	(118	)	$	(213	)
Ameren:
Level 1	$	6		$	1		$	—		$	—		$	7
Level 2(a)	(12		)	(12		)	(1		)	—			(25		)
Level 3(b)	(9		)	(28		)	(30		)	(118		)	(185		)
Total	$	(15	)	$	(39	)	$	(31	)	$	(118	)	$	(203	)

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

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

ITEM 4. CONTROLS AND PROCEDURES.

(a) Evaluation of Disclosure Controls and Procedures

As of June 30, 2018, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and the principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on those evaluations, as of June 30, 2018, 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 officer and its principal financial officer, to allow timely decisions regarding required disclosure.

(b) Changes in Internal Controls over Financial Reporting

There has been no change in any of the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, each of their internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. Material legal and administrative proceedings, which are discussed in Note 2 – Rate and Regulatory Matters, Note 9 – Commitments and Contingencies, and Note 10 – Callaway Energy Center, under Part I, Item 1, of this report include the following:

• Ameren Illinois’ natural gas regulatory rate review filed with the ICC in January 2018;

• Ameren Illinois’ annual electric distribution service formula rate update filed with the ICC in April 2018;

• Ameren Illinois’ annual electric energy efficiency formula rate update filed with the ICC in June 2018;

• Ameren Missouri’s proposed RESRAM filed with the MoPSC in June 2018;

• Ameren Missouri’s MEEIA filing with the MoPSC in June 2018;

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

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• litigation against Ameren Missouri with respect to the Clean Air Act; and

• remediation matters associated with former MGP and waste disposal sites of the Ameren Companies.

ITEM 1A. RISK FACTORS.

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

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

Ameren Corporation, Ameren Missouri, and Ameren Illinois did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from April 1, 2018 to June 30, 2018.

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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:
Instruments Defining Rights of Security Holders, Including Indentures
4.1	Ameren Ameren Missouri	Supplemental Indenture, dated as of April 1, 2018, to Ameren Missouri Mortgage for 4.000% First Mortgage Bonds due 2048	April 6, 2018 Form 8-K, Exhibit 4.2, File No. 1-2967
4.2	Ameren Ameren Illinois	Supplemental Indenture, dated as of May 1, 2018, to Ameren Illinois Mortgage for 3.80% First Mortgage Bonds due 2028	May 22, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672
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: August 7, 2018

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EX-12.1

Exhibit 12.1

Ameren Corporation

Computation of Ratio of Earnings to Fixed Charges

(Millions of Dollars, Except Ratio)

	Six Months Ended June 30,
	2018
Earnings available for fixed charges, as defined:
Net income attributable to Ameren Corporation	$	390
Loss from equity investee	1
Tax expense based on income	116
Fixed charges excluding subsidiary preferred stock dividends tax adjustment	216
Earnings available for fixed charges, as defined	$	723
Fixed charges, as defined:
Interest expense on short-term and long-term debt	$	201
Estimated interest cost within rental expense	1
Amortization of net debt premium, discount, and expenses	11
Subsidiary preferred stock dividends	3
Adjust subsidiary preferred stock dividends to pretax basis	1
Total fixed charges, as defined	$	217
Consolidated ratio of earnings to fixed charges	3.3

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

(Millions of Dollars, Except Ratios)

	Six Months Ended June 30,
	2018
Earnings available for fixed charges, as defined:
Net income	$	208
Tax expense based on income	67
Fixed charges	110
Earnings available for fixed charges, as defined	$	385
Fixed charges, as defined:
Interest expense on short-term and long-term debt	$	106
Estimated interest cost within rental expense	1
Amortization of net debt premium, discount, and expenses	3
Total fixed charges, as defined	$	110
Ratio of earnings to fixed charges	3.5
Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends	$	2
Adjustment to pretax basis	—
	$	2
Combined fixed charges and preferred stock dividend requirements	$	112
Ratio of earnings to combined fixed charges and preferred stock dividend requirements	3.4

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

(Millions of Dollars, Except Ratios)

	Six Months Ended June 30,
	2018
Earnings available for fixed charges, as defined:
Net income	$	159
Tax expense based on income	50
Fixed charges	77
Earnings available for fixed charges, as defined	$	286
Fixed charges, as defined:
Interest expense on short-term and long-term debt	$	70
Amortization of net debt premium, discount, and expenses	7
Total fixed charges, as defined	$	77
Ratio of earnings to fixed charges	3.7
Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends	$	2
Adjustment to pretax basis	—
	$	2
Combined fixed charges and preferred stock dividend requirements	$	79
Ratio of earnings to combined fixed charges and preferred stock dividend requirements	3.6

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 June 30, 2018 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: August 7, 2018

 /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 June 30, 2018 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: August 7, 2018

 /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 June 30, 2018 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: August 7, 2018

 /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 June 30, 2018 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: August 7, 2018

 /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 June 30, 2018 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: August 7, 2018

 /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 June 30, 2018 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: August 7, 2018

 /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 June 30, 2018 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: August 7, 2018

 
/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 June 30, 2018 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: August 7, 2018

 /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 June 30, 2018 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: August 7, 2018

 /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	6 Months Ended
	Jun. 30, 2018	Jul. 31, 2018
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
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		244,039,980
Union Electric Company
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
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	Jun. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
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) and Comprehensive Income (Loss) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Operating Revenues:
Revenue from Contract with Customer, Including Assessed Tax	$ 1,563	$ 1,537	$ 3,148	$ 3,052
Operating Expenses:
Fuel	186	189	374	395
Utilities Operating Expense, Purchased Power	142	150	305	330
Utilities Operating Expense, Gas and Petroleum Purchased	51	41	222	171
Other operations and maintenance	439	431	870	849
Depreciation and amortization	238	222	472	443
Taxes other than income taxes	122	117	247	235
Total operating expenses	1,178	1,150	2,490	2,423
Operating Income	385	387	658	629
Other Income (Expense), Net	29	20	52	38
Interest Charges	100	99	201	198
Income Before Income Taxes	314	308	509	469
Income Taxes	74	114	116	171
Net income	240	194	393	298
Less: Net Income Attributable to Noncontrolling Interests	1	1	3	3
Net Income (Loss) Available to Common Stockholders, Basic	239	193	390	295
Pension and other postretirement benefit plan activity, net of income taxes (benefit)	(2)	2	(1)	2
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	238	196	392	300
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	1	1	3	3
Comprehensive Income	$ 237	$ 195	$ 389	$ 297
Earnings Per Share, Basic and Diluted [Abstract]
Earnings Per Share, Basic	$ 0.98	$ 0.79	$ 1.60	$ 1.21
Earnings Per Share, Diluted	0.97	0.79	1.59	1.21
Dividends per Common Share (in dollars per share)	$ 0.4575	$ 0.44	$ 0.915	$ 0.88
Average Common Shares Outstanding - Basic (in shares)	243.7	242.6	243.3	242.6
Weighted Average Number of Shares Outstanding, Diluted	245.8	243.5	245.1	243.7
Electricity
Operating Revenues:
Revenue from Contract with Customer, Including Assessed Tax	$ 1,396	$ 1,382	$ 2,619	$ 2,589
Natural Gas
Operating Revenues:
Revenue from Contract with Customer, Including Assessed Tax	167	155	529	463
Union Electric Company
Operating Revenues:
Revenue from Contract with Customer, Including Assessed Tax	955	934	1,747	1,725
Operating Expenses:
Fuel	186	189	374	395
Utilities Operating Expense, Purchased Power	40	69	82	160
Utilities Operating Expense, Gas and Petroleum Purchased	8	5	32	25
Other operations and maintenance	241	224	473	443
Depreciation and amortization	138	132	274	265
Taxes other than income taxes	84	85	164	160
Total operating expenses	697	704	1,399	1,448
Operating Income	258	230	348	277
Other Income (Expense), Net	16	16	29	32
Interest Charges	51	53	102	107
Income Before Income Taxes	223	193	275	202
Income Taxes	54	72	67	75
Net income	169	121	208	127
Preferred Stock Dividends	1	1	2	2
Net Income (Loss) Attributable to Parent	168	120	206	125
Union Electric Company | Electricity
Operating Revenues:
Revenue from Contract with Customer, Including Assessed Tax	930	912	1,671	1,659
Union Electric Company | Natural Gas
Operating Revenues:
Revenue from Contract with Customer, Including Assessed Tax	25	22	76	66
Ameren Illinois Company
Operating Revenues:
Revenue from Contract with Customer, Including Assessed Tax	578	576	1,338	1,279
Operating Expenses:
Utilities Operating Expense, Purchased Power	105	87	229	188
Utilities Operating Expense, Gas and Petroleum Purchased	43	36	190	146
Other operations and maintenance	196	212	395	412
Depreciation and amortization	94	85	184	168
Taxes other than income taxes	35	28	76	68
Total operating expenses	473	448	1,074	982
Operating Income	105	128	264	297
Other Income (Expense), Net	13	3	19	3
Interest Charges	37	36	74	73
Income Before Income Taxes	81	95	209	227
Income Taxes	18	37	50	89
Net income	63	58	159	138
Preferred Stock Dividends	1	1	2	2
Net Income (Loss) Attributable to Parent	62	57	157	136
Ameren Illinois Company | Electricity
Operating Revenues:
Revenue from Contract with Customer, Including Assessed Tax	436	442	885	881
Ameren Illinois Company | Natural Gas
Operating Revenues:
Revenue from Contract with Customer, Including Assessed Tax	$ 142	$ 134	$ 453	$ 398

XML

Consolidated Statement of Income (Loss) and Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Statement [Abstract]
Pension and other postretirement benefit plan activity, tax expense (benefit)	$ 0	$ 1	$ 0	$ 1

XML

Consolidated Balance Sheet - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 29	$ 10
Accounts receivable - trade (less allowance for doubtful accounts)	560	445
Unbilled revenue	371	323
Miscellaneous accounts and notes receivable	74	70
Inventories	475	522
Current regulatory assets	104	144
Other current assets	72	98
Total current assets	1,685	1,612
Property, Plant, and Equipment, Net	21,998	21,466
Investments and Other Assets:
Nuclear decommissioning trust fund	714	704
Goodwill	411	411
Regulatory assets	1,205	1,230
Other assets	626	522
Total investments and other assets	2,956	2,867
TOTAL ASSETS	26,639	25,945
Current Liabilities:
Current maturities of long-term debt	847	841
Short-term Debt	506	484
Accounts and wages payable	565	902
Taxes accrued	139	52
Interest accrued	109	99
Customer deposits	114	108
Current regulatory liabilities	133	128
Other current liabilities	298	326
Total current liabilities	2,711	2,940
Long-term Debt, Net	7,613	7,094
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	2,584	2,506
Accumulated Deferred Investment Tax Credit	46	49
Regulatory Liability, Noncurrent	4,540	4,387
Asset retirement obligations	641	638
Pension and other postretirement benefits	545	545
Other deferred credits and liabilities	431	460
Total deferred credits and other liabilities	8,787	8,585
Commitments and Contingencies
Stockholders' Equity:
Common Stock	2	2
Other paid-in capital	5,576	5,540
Retained earnings	1,827	1,660
Accumulated other comprehensive loss	(19)	(18)
Stockholder's equity	7,386	7,184
Noncontrolling Interest	142	142
Total equity	7,528	7,326
TOTAL LIABILITIES AND EQUITY	26,639	25,945
Union Electric Company
Current Assets:
Cash and cash equivalents	17	0
Due from Related Parties, Current	66	0
Accounts receivable - trade (less allowance for doubtful accounts)	285	200
Accounts receivable - affiliates	23	11
Unbilled revenue	256	165
Miscellaneous accounts and notes receivable	55	35
Inventories	380	388
Current regulatory assets	48	56
Other current assets	42	50
Total current assets	1,172	905
Property, Plant, and Equipment, Net	11,835	11,751
Investments and Other Assets:
Nuclear decommissioning trust fund	714	704
Regulatory assets	367	395
Other assets	304	288
Total investments and other assets	1,385	1,387
TOTAL ASSETS	14,392	14,043
Current Liabilities:
Current maturities of long-term debt	534	384
Short-term Debt	0	39
Accounts and wages payable	226	475
Accounts payable - affiliates	125	60
Taxes accrued	110	30
Interest accrued	69	54
Current regulatory liabilities	50	19
Other current liabilities	107	103
Total current liabilities	1,221	1,164
Long-term Debt, Net	3,668	3,577
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,614	1,650
Accumulated Deferred Investment Tax Credit	45	48
Regulatory Liability, Noncurrent	2,754	2,664
Asset retirement obligations	637	634
Pension and other postretirement benefits	209	213
Other deferred credits and liabilities	7	12
Total deferred credits and other liabilities	5,266	5,221
Commitments and Contingencies
Stockholders' Equity:
Common Stock	511	511
Other paid-in capital	1,858	1,858
Preferred stock	80	80
Retained earnings	1,788	1,632
Stockholder's equity	4,237	4,081
TOTAL LIABILITIES AND EQUITY	14,392	14,043
Ameren Illinois Company
Current Assets:
Cash and cash equivalents	0	0
Accounts receivable - trade (less allowance for doubtful accounts)	251	234
Accounts receivable - affiliates	21	9
Unbilled revenue	115	158
Miscellaneous accounts and notes receivable	29	35
Inventories	95	134
Current regulatory assets	55	87
Other current assets	10	15
Total current assets	576	672
Property, Plant, and Equipment, Net	8,716	8,293
Investments and Other Assets:
Goodwill	411	411
Regulatory assets	822	822
Other assets	246	147
Total investments and other assets	1,479	1,380
TOTAL ASSETS	10,771	10,345
Current Liabilities:
Current maturities of long-term debt	313	457
Short-term Debt	0	62
Due to Related Parties, Current	31	0
Accounts and wages payable	291	337
Accounts payable - affiliates	44	70
Taxes accrued	15	19
Interest accrued	30	33
Customer deposits	75	69
Current environmental remediation	43	42
Current regulatory liabilities	65	92
Other current liabilities	150	177
Total current liabilities	1,057	1,358
Long-term Debt, Net	2,800	2,373
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,045	1,021
Regulatory Liability, Noncurrent	1,689	1,629
Pension and other postretirement benefits	292	285
Environmental remediation	123	134
Other deferred credits and liabilities	218	235
Total deferred credits and other liabilities	3,367	3,304
Commitments and Contingencies
Stockholders' Equity:
Common Stock	0	0
Other paid-in capital	2,093	2,013
Preferred stock	62	62
Retained earnings	1,392	1,235
Stockholder's equity	3,547	3,310
TOTAL LIABILITIES AND EQUITY	$ 10,771	$ 10,345

XML

Consolidated Balance Sheet (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Accounts receivable - trade allowance for doubtful accounts	$ 25	$ 19
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	400,000,000	400,000,000
Common stock, shares outstanding (in shares)	243,600,000	242,600,000
Union Electric Company
Accounts receivable - trade allowance for doubtful accounts	$ 9	$ 7
Common stock, par value (in dollars per share)	$ 5	$ 5
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares outstanding (in shares)	102,100,000	102,100,000
Ameren Illinois Company
Accounts receivable - trade allowance for doubtful accounts	$ 16	$ 12
Common stock, no par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized (in shares)	45,000,000	45,000,000
Common stock, shares outstanding (in shares)	25,500,000	25,500,000

XML

Consolidated Statement of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cash Flows From Operating Activities:
Net income	$ 393	$ 298
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	463	433
Amortization of nuclear fuel	48	48
Amortization of debt issuance costs and premium/discounts	11	11
Deferred income taxes and investment tax credits, net	81	175
Allowance for equity funds used during construction	(14)	(10)
Stock-based compensation costs	10	8
Other	11	(5)
Changes in assets and liabilities:
Receivables	(170)	(54)
Inventories	46	14
Accounts and wages payable	(209)	(183)
Taxes accrued	105	83
Regulatory assets and liabilities	83	(4)
Assets, other	8	22
Liabilities, other	(50)	21
Pension and other postretirement benefits	4	6
Net cash provided by operating activities	820	863
Cash Flows From Investing Activities:
Capital expenditures	(1,112)	(998)
Nuclear fuel expenditures	(16)	(50)
Payments to Acquire Investments to be Held in Decommissioning Trust Fund	(129)	(161)
Proceeds from Decommissioning Trust Fund Assets	122	152
Other	6	(2)
Net cash used in investing activities	(1,129)	(1,059)
Cash Flows From Financing Activities:
Dividends on common stock	(223)	(214)
Dividends paid to noncontrolling interest holders	(3)	(3)
Short-term debt, net	21	334
Repayments of Long-term Debt	(323)	(425)
Proceeds from Issuance of Long-term Debt	853	549
Issuance of common stock	40	0
Repurchases of common stock for stock-based compensation	0	(24)
Employee payroll taxes related to stock-based compensation	(19)	(15)
Payment of Financing and Stock Issuance Costs	(9)	(4)
Other	0	(1)
Net cash provided by financing activities	337	197
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect	28	1
Noncash financing activity - Issuance of common stock for stock-based compensation	35	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	96	53
Union Electric Company
Cash Flows From Operating Activities:
Net income	208	127
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	265	255
Amortization of nuclear fuel	48	48
Amortization of debt issuance costs and premium/discounts	3	3
Deferred income taxes and investment tax credits, net	(24)	13
Allowance for equity funds used during construction	(11)	(9)
Other	10	3
Changes in assets and liabilities:
Receivables	(205)	(124)
Inventories	8	(7)
Accounts and wages payable	(160)	(169)
Taxes accrued	152	153
Regulatory assets and liabilities	106	57
Assets, other	(2)	19
Liabilities, other	11	24
Pension and other postretirement benefits	3	3
Net cash provided by operating activities	412	396
Cash Flows From Investing Activities:
Capital expenditures	(454)	(355)
Nuclear fuel expenditures	(16)	(50)
Payments to Acquire Investments to be Held in Decommissioning Trust Fund	(129)	(161)
Proceeds from Decommissioning Trust Fund Assets	122	152
Money pool advances, net	(66)	161
Net cash used in investing activities	(543)	(253)
Cash Flows From Financing Activities:
Dividends on common stock	(50)	(172)
Dividends on preferred stock	(2)	(2)
Short-term debt, net	(39)	60
Repayments of Long-term Debt	(179)	(425)
Proceeds from Issuance of Long-term Debt	423	399
Payment of Financing and Stock Issuance Costs	(4)	(3)
Net cash provided by financing activities	149	(143)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect	18	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	25	5
Ameren Illinois Company
Cash Flows From Operating Activities:
Net income	159	138
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	184	168
Amortization of debt issuance costs and premium/discounts	7	7
Deferred income taxes and investment tax credits, net	13	116
Allowance for equity funds used during construction	(3)	(1)
Other	(3)	0
Changes in assets and liabilities:
Receivables	23	70
Inventories	38	20
Accounts and wages payable	(35)	(17)
Taxes accrued	(23)	(68)
Regulatory assets and liabilities	(20)	(54)
Assets, other	4	3
Liabilities, other	(58)	(10)
Pension and other postretirement benefits	(2)	2
Net cash provided by operating activities	287	375
Cash Flows From Investing Activities:
Capital expenditures	(602)	(484)
Other	3	4
Net cash used in investing activities	(599)	(480)
Cash Flows From Financing Activities:
Dividends on preferred stock	(2)	(2)
Short-term debt, net	(62)	108
Proceeds from (Repayments of) Short-term Debt, Maturing in More than Three Months	31
Repayments of Long-term Debt	(144)	0
Proceeds from Issuance of Long-term Debt	430
Payment of Financing and Stock Issuance Costs	(5)
Capital contribution from parent	80
Other	0	(1)
Net cash provided by financing activities	328	105
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect	16	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 57	$ 28

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Summary Of Significant Accounting Policies

6 Months Ended

Jun. 30, 2018

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 whose primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Ameren also has other subsidiaries that conduct other activities, such as providing shared services. Ameren evaluates competitive electric transmission investment opportunities 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 and Mark Twain projects, and placed the Spoon River project in service in February 2018.

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.

As of both June 30, 2018, and December 31, 2017, Ameren had unconsolidated variable interests as a limited partner in various equity method investments, totaling $17 million, included in “Other assets” on Ameren’s consolidated balance sheet. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly affect the activities of these variable interest entities. As of June 30, 2018, the maximum exposure to loss related to these variable interests is limited to the investment in these partnerships of $17 million plus associated outstanding funding commitments of $19 million.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and accompanying notes included in the Form 10-K.

Cash, Cash Equivalents, and Restricted Cash

Cash and cash equivalents include short-term, highly liquid investments purchased with an original maturity of three months or less. Cash and cash equivalents subject to legal or contractual restrictions and not readily available for use for general corporate purposes are classified as restricted cash.

In November 2016, the FASB issued authoritative guidance that requires, including on a retrospective basis, restricted cash to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Our adoption of this guidance, effective January 2018, did not result in material changes to previously reported cash flows from operating, investing, or financing activities.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets and the statements of cash flows as of June 30, 2018 and 2017, and December 31, 2017 and 2016:

	June 30, 2018						December 31, 2017						June 30, 2017						December 31, 2016
	Ameren		Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois
Cash and cash equivalents(a)	$	29	$	17	$	—	$	10	$	—	$	—	$	10	$	—	$	—	$	9	$	—	$	—
Restricted cash included in “Other current assets”	12		4		6		21		5		6		19		4		5		20		4		6
Restricted cash included in “Other assets”	51		—		51		35		—		35		23		—		23		22		—		22
Restricted cash included in “Nuclear decommissioning trust fund”	4		4		(b)		2		2		(b)		1		1		(b)		1		1		(b)
Total cash, cash equivalents, and restricted cash(c)	$	96	$	25	$	57	$	68	$	7	$	41	$	53	$	5	$	28	$	52	$	5	$	28

(a) As presented on the balance sheet.

(b) Not applicable.

(c) As presented on the statement of cash flows.

Restricted cash included in Ameren’s other current assets primarily represents participant funds from Ameren (parent)’s DRPlus and funds held by an irrevocable Voluntary Employee Beneficiary Association trust, which provides health care benefits for active employees. Restricted cash included in Ameren Missouri’s and Ameren Illinois’ other current assets primarily represents funds held by the trust.

Restricted cash included in Ameren’s and Ameren Illinois’ other assets primarily represents amounts in a trust fund restricted for the use of funding certain asbestos-related claims and amounts collected under a cost recovery rider that are restricted for use in the procurement of renewable energy credits.

Supplemental Cash Flow Information

The following table provides noncash investing activity excluded from the statements of cash flows for the six months ended June 30, 2018 and 2017:

	June 30, 2018						June 30, 2017
	Ameren(a)		Ameren Missouri		Ameren Illinois		Ameren(a)		Ameren Missouri		Ameren Illinois
Accrued capital expenditures	$	233	$	80	$	147	$	175	$	61	$	79
Net realized and unrealized gain – nuclear decommissioning trust fund	1		1		(b)		36		36		(b)

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

(b) Not applicable.

Accounts Receivable

"Accounts receivable – trade" on Ameren's and Ameren Illinois' balance sheets include certain receivables purchased at a discount from alternative retail electric suppliers that elect to participate in the utility consolidated billing program. At June 30, 2018, and December 31, 2017, "Other current liabilities" on Ameren's and Ameren Illinois' balance sheets included payables for purchased receivables of $40 million and $31 million, respectively.

For the three and six months ended June 30, 2018 and 2017, the Ameren Companies recorded immaterial bad debt expense.

Asset Retirement Obligations

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the six months ended June 30, 2018:

	Ameren Missouri				Ameren Illinois(a)		Ameren
Balance at December 31, 2017	$	640		(b)	$	4	$	644		(b)
Liabilities settled	(2		)		(c)		(2		)
Accretion(d)	14				(c)		14
Change in estimates(e)	(9		)		—		(9		)
Balance at June 30, 2018	$	643		(b)	$	4	$	647		(b)

(a) Included in “Other deferred credits and liabilities” on the balance sheet.

(b) Balance included $6 million in “Other current liabilities” on the balance sheet as of both December 31, 2017, and June 30, 2018, respectively.

(c) Less than $1 million.

(d) Accretion expense attributable to Ameren Missouri was recorded as a decrease to regulatory liabilities.

(e) Ameren Missouri changed its fair value estimate primarily due to a reduction in the cost estimate for closure of certain CCR storage facilities.

Company-owned Life Insurance

Ameren and Ameren Illinois have company-owned life insurance, which is recorded at the net cash surrender value. The net cash surrender value is the amount that can be realized under the insurance policies at the balance sheet date. As of June 30, 2018, the cash surrender value of company-owned life insurance at Ameren and Ameren Illinois was $249 million (December 31, 2017 – $265 million) and $117 million (December 31, 2017 – $129 million), respectively, while total borrowings against the policies were $107 million (December 31, 2017 – $120 million) at both Ameren and Ameren Illinois. Ameren and Ameren Illinois have the right to offset the borrowings against the cash surrender value of the policies and, consequently, present the net asset in “Other assets” on their respective balance sheets.

Stock-based Compensation

The following table summarizes Ameren's nonvested performance share unit and restricted stock unit activity for the six months ended June 30, 2018:

	Performance Share Units				Restricted Stock Units
	Share Units		Weighted-average Fair Value per Share Unit		Stock Units		Weighted-average Fair Value per Stock Unit
Nonvested at January 1, 2018(a)	895,489		$	52.28	—		$	—
Granted	306,252		62.88		184,351		57.60
Forfeitures	(54,213	)	49.72		(3,560	)	58.99
Undistributed vested units(b)	(145,169	)	53.50		(12,983	)	58.98
Vested and distributed	(176,043	)	52.88		—		—
Nonvested at June 30, 2018(c)	826,316		$	56.03	167,808		$	57.46

(a) Does not include 712,572 undistributed vested performance share units.

(b) Undistributed vested units are awards that vested due to attainment of retirement eligibility by certain employees, but have not yet been distributed. For undistributed vested performance share units, the number of shares issued for retirement-eligible employees will vary depending on actual performance over the three-year performance period.

(c) Does not include 476,361 undistributed vested performance share units and 12,983 undistributed vested restricted stock units.

Performance Share Units

A performance share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, certain specified market conditions have been met and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date. In the event of a participant’s death or retirement at age 55 or older with five or more years of service, awards vest on a pro rata basis over the three-year performance period. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals.

The fair value of each performance share unit granted in 2018 was determined to be $62.88, which was based on Ameren’s closing common share price of $58.99 at December 31, 2017, 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, 2018, 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 1.98% and volatility of 15% to 23% for the peer group.

Restricted Stock Units

Restricted stock units vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if the individual remains employed with Ameren through the payment date of the awards. Generally, in the event of a participant’s death or retirement at age 55 or older with five or more years of service, awards vest on a pro rata basis. The payout date of the awards is approximately 38 months after the grant date. The fair value of each restricted stock unit is determined by Ameren’s closing common share price on the grant date.

Deferred Compensation

As of June 30, 2018, and December 31, 2017, “Other deferred credits and liabilities” on Ameren’s balance sheet included deferred compensation obligations of $85 million and $86 million, respectively, recorded at the present value of future benefits to be paid.

Operating Revenues

In the first quarter of 2018, we adopted authoritative accounting guidance related to revenue from contracts with customers using the full retrospective method, with no material changes to the amount or timing of revenue recognition. We record revenues from contracts with customers for various electric and natural gas services, which primarily consist of retail distribution, electric transmission, and off-system arrangements. When more than one performance obligation exists in a contract, the consideration under the contract is allocated to the performance obligations based on the relative standalone selling price.

Electric and natural gas retail distribution revenues are earned when the commodity is delivered to our customers. We accrue an estimate of electric and natural gas retail distribution revenues for service provided but unbilled at the end of each accounting period.

Electric transmission revenues are earned as electric transmission services are provided.

Off-system revenues are primarily comprised of MISO revenues and wholesale bilateral revenues. MISO revenues include the sale of electricity, capacity, and ancillary services. Wholesale bilateral revenues include the sale of electricity and capacity. MISO-related electricity and wholesale bilateral electricity revenues are earned as electricity is delivered. MISO-related capacity and ancillary service revenues and wholesale bilateral capacity revenues are earned as services are provided.

Retail distribution, electric transmission, and off-system revenues, including the underlying components described above, represent a series of goods or services that are substantially the same and have the same pattern of transfer over time to our customers. Revenues from contracts with customers is equal to the amounts billed and our estimate of electric and natural gas retail distribution services provided but unbilled at the end of each accounting period. Revenues are billed at least monthly, and payments are due less than one month after goods and/or services are provided. See Note 12 – Segment Information for disaggregated revenue information.

For certain regulatory recovery mechanisms that are alternative revenue programs, rather than revenues from contracts with customers, we 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 from the end of the year. Our alternative revenue programs include revenue requirement reconciliations, MEEIA, and VBA. These revenues are subsequently recognized as revenues from contracts with customers when billed, with an offset to alternative revenue program revenues.

The Ameren Companies elected to exclude disclosure related to the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied as of the end of the reporting period for contracts with an initial expected term of one year or less. As of June 30, 2018 and 2017, our remaining performance obligations were immaterial.

Excise Taxes

Ameren Missouri and Ameren Illinois collect from their customers excise taxes, including municipal and state excise taxes and gross receipts taxes, that are levied on the sale or distribution of natural gas and electricity. Excise taxes are recorded gross in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” on the statements of income. The following table presents the excise taxes recorded in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” for the three and six months ended June 30, 2018 and 2017:

	Three Months					Six Months
	2018		2017			2018		2017
Ameren Missouri	$	46	$	40		$	80	$	71
Ameren Illinois	28		23		(a)	63		57		(a)
Ameren	$	74	$	63	(a)	$	143	$	128	(a)

(a) Amounts have been adjusted from those previously reported to reflect additional excise taxes for the three and six months ended June 30, 2017, respectively.

Income Taxes

The following table presents a reconciliation of the federal statutory corporate income tax rate to the effective income tax rate for the three and six months ended June 30, 2018 and 2017:

	Ameren		Ameren Missouri			Ameren Illinois
Three Months	2018	2017	2018		2017	2018	2017
Federal statutory corporate income tax rate:	21%	35%	21%		35%	21%	35%
Increases (decreases) from:
Amortization of excess deferred taxes	(1)	—	—	(a)	—	(5)	—
Other depreciation differences	—	—	—		—	(1)	(1)
Amortization of deferred investment tax credit	—	—	(1)		(1)	—	—
State tax	5	4	4		3	8	5
Tax credits	(1)	—	—		—	—	—
Other permanent items	—	(1)	—		—	—	—
Effective income tax rate	24%	38%	24%		37%	23%	39%
Six Months
Federal statutory corporate income tax rate:	21%	35%	21%		35%	21%	35%
Increases (decreases) from:
Amortization of excess deferred taxes	(2)	—	—	(a)	—	(4)	—
Amortization of deferred investment tax credit	(1)	(1)	(1)		(1)	—	—
State tax	6	5	4		3	7	5
Other permanent items	(1)	(2)	—		—	—	(1)
Effective income tax rate	23%	37%	24%		37%	24%	39%

(a) Based on an order issued by the MoPSC in July 2018, Ameren Missouri began amortizing excess deferred taxes in August 2018. See Note 2 – Rate and Regulatory Matters for additional information.

In June 2018, legislation modifying Missouri tax law was enacted to decrease the state's corporate income tax rate from 6.25% to 4%, effective January 1, 2020. As a result, in the second quarter of 2018, Ameren’s and Ameren Missouri’s accumulated deferred tax balances were revalued, resulting in a net decrease to their accumulated deferred tax liability of $33 million, which was offset by a regulatory liability. Additionally, Ameren recorded an immaterial amount to income tax expense. As a result of its expected PISA election under Missouri Senate Bill 564, which would prohibit a change in electric base rates prior to April 2020, Ameren Missouri anticipates that the effect of this tax decrease will be reflected in customer rates upon completion of its next regulatory rate review. Ameren (parent) and nonregistrant subsidiaries do not expect this income tax decrease to have a material impact on net income prospectively.

Earnings Per Share

Basic earnings per share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of common shares outstanding during the period. Earnings per diluted share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of diluted common shares outstanding during the period. Earnings per diluted share reflects the dilution that would occur if certain stock-based performance share units were assumed to be settled. The number of performance share units assumed to be settled was 2.1 million and 1.8 million in the three and six months ended June 30, 2018, respectively, and 0.8 million and 1.1 million, respectively, in the year-ago periods. There were no potentially dilutive securities excluded from the earnings per diluted share calculations for the three and six months ended June 30, 2018 and 2017.

Accounting and Reporting Developments

In the first quarter of 2018, the Ameren Companies adopted authoritative accounting guidance on various topics. See the Operating Revenues section above for more information on our adoption of the guidance on revenue from contracts with customers. See Note 11 – Retirement Benefits for more information on our adoption of the guidance on the presentation of net periodic pension and postretirement benefit cost. See the Cash, Cash Equivalents, and Restricted Cash section above for more information on our adoption of the guidance on restricted cash. Our adoption of the guidance on the recognition and measurement of financial assets and financial liabilities did not have a material impact on our results of operations or financial position.

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, the measurement of credit losses on financial instruments, and the reclassification of certain tax effects from accumulated OCI.

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Rate And Regulatory Matters

6 Months Ended

Jun. 30, 2018

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

Missouri Senate Bill 564

On June 1, 2018, Missouri Senate Bill 564 was enacted. The section of the law applicable to the TCJA became effective immediately; the remaining sections, including the ability to elect PISA, become effective August 28, 2018. The law resulted in certain changes to Missouri utility laws that affect the regulation of Ameren Missouri’s electric service business. These changes include the reduction of customer rates to pass through the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA and, at each electric utility's election, the use of PISA. Electric utilities that do not elect to use PISA will be eligible to request permission to implement revenue decoupling of residential and other non-demand metered customer classes. The law required the MoPSC to authorize a reduction in Ameren Missouri’s rates to pass through the effect of the TCJA within 90 days of the law’s effective date. In July 2018, the MoPSC authorized Ameren Missouri to reduce its annual revenue requirement by$167 millionand reflect that reduction in rates beginning August 1, 2018. The reduction included $74 million for the amortization of excess accumulated deferred income taxes. In addition, Ameren Missouri recorded a reduction to revenue and a corresponding regulatory liability of $47 million for the excess amounts collected in rates related to the TCJA from January 1, 2018, through June 30, 2018. An additional amount will be recorded for July 2018 revenues. The regulatory liability will be reflected in customer rates over a period of time to be determined by the MoPSC in the next regulatory rate review.

Upon Ameren Missouri’s expected PISA election, it would be permitted to defer and recover 85% of the depreciation expense and return on rate base on certain property, plant, and equipment placed in-service after August 28, 2018, and not included in base rates. Eligible PISA deferrals would exclude amounts related to new coal-fired, nuclear, and natural gas generating units and service to new customer premises. Upon approval in a regulatory rate review, PISA deferrals would be added to rate base prospectively and earn a return based on Ameren Missouri’s weighted-average cost of capital over a recovery period of 20 years. For electric utilities electing to use PISA, additional provisions apply, including limitations on customer rate increases. Ameren Missouri’s customer rate increases would be limited to a 2.85% compound annual growth rate in the average overall customer rate per kilowatthour, applied to electric rates effective April 1, 2017, less half of the 2018 savings from the TCJA that was passed on to customers. Upon election to use PISA, Ameren Missouri’s electric base rates would be frozen until April 1, 2020. Recoveries under the MEEIA, the FAC, and the RESRAM riders would not be frozen; however, except for costs recoverable under the MEEIA rider, Ameren Missouri would be unable to recover any amounts above the 2.85% cap from customers. If rate changes from the FAC or the RESRAM riders would cause rates to temporarily exceed the 2.85% cap, the overage would be deferred for future recovery in the next regulatory rate review; however, rates established in such regulatory rate review would be subject to the rate cap. Any deferred overages approved for recovery would be subject to deferral and recovered in a manner consistent with costs recovered under PISA. Both the rate cap and PISA election would be effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028. Ameren Missouri’s expected PISA election will support Ameren Missouri's ability to invest approximately $1 billion of incremental capital over the 2019 to 2023 period to strengthen and modernize Missouri's electric grid.

MoPSC Federal Income Tax Proceedings

In February 2018, the MoPSC initiated proceedings to investigate how the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA should be reflected in rates paid by customers of Missouri’s regulated utilities, including rates paid by electric and natural gas customers of Ameren Missouri. The proceeding for Ameren Missouri’s electric service business was dismissed after Missouri Senate Bill 564 was enacted on June 1, 2018, but the proceeding is still pending for Ameren Missouri’s natural gas distribution business. As of June 30, 2018, the potential reduction in natural gas customer rates is immaterial. The MoPSC is under no deadline to issue an order in the natural gas proceeding.

Wind Generation Facility and RESRAM

In the second quarter of 2018, Ameren Missouri entered into an agreement with a subsidiary of Terra-Gen, LLC to acquire a 400-megawatt wind generation facility after construction. The facility is expected to be located in northeastern Missouri and to be completed in 2020. The acquisition is subject to certain conditions, including the issuance of a certificate of convenience and necessity by the MoPSC, obtaining a MISO transmission interconnection agreement, and approval by the FERC. Ameren Missouri has filed for the certificate of convenience and necessity with the MoPSC. This facility would help Ameren Missouri to comply with the state renewable energy standard.In addition, Ameren Missouri requested the MoPSC to authorize a proposed RESRAM that would allow Ameren Missouri to adjust customer rates, including recovery of interest at a short-term borrowing rate, on an annual basis without a traditional regulatory rate review. The RESRAM is designed to mitigate the impacts of regulatory lag for investments in wind generation and other renewables by providing more timely recovery of costs and would provide Ameren Missouri a greater opportunity to earn its allowed return on investment. Ameren Missouri anticipates a decision by January 2019 related to the certificate of convenience and necessity and proposed RESRAM.

Renewable Choice Program

In June 2018, the MoPSC approved Ameren Missouri’s Renewable Choice Program, which allows large commercial and industrial customers and municipalities to receive up to 100 percent of their energy from renewable resources. The tariff-based program is designed to recover the costs of the election, net of changes in the market price of such energy. Based on customer contracts, the program enables Ameren Missouri to supply up to 400 megawatts of renewable wind energy generation, up to 200 megawatts of which it could own. As applicable, the addition of generation by Ameren Missouri would be subject to the issuance of a certificate of convenience and necessity by the MoPSC, obtaining transmission interconnection agreements with the MISO or other RTOs, and approval by the FERC. This generation would be incremental to the expected renewable generation included in the 2017 IRP. Without extension, the option to elect into the program will terminate in the third quarter of 2023.

MEEIA

In June 2018, Ameren Missouri filed a proposed customer energy-efficiency plan with the MoPSC under the MEEIA. This filing proposed a six-year plan, which includes a portfolio of customer energy-efficiency programs, along with a cost recovery mechanism. If the plan is approved, beginning in March 2019, Ameren Missouri intends to invest an average of $92 million per program year in the proposed customer energy-efficiency programs. Ameren Missouri requested continued use of a MEEIA rider, which allows Ameren Missouri to collect from or refund to customers any difference in the actual amounts incurred and the amounts collected from customers for the MEEIA program costs and its lost revenues. In addition, Ameren Missouri requested incentives to earn additional revenues by achieving certain customer energy-efficiency goals, increasing from $10 million to $24 million annually, for a total of $115 million over the six-year period if 100% of its annual customer energy-efficiency goals are achieved. A decision by the MoPSC in this proceeding is anticipated by the first quarter of 2019.

The MEEIA 2016 program provided Ameren Missouri with a performance incentive to earn additional revenues by achieving certain customer energy-efficiency goals, including $27 million if 100% of the goals were achieved during the three-year period beginning March 2016, with the potential to earn more if Ameren Missouri’s energy savings exceeded those goals. In September 2017, Ameren Missouri received an order from the MoPSC approving Ameren Missouri’s energy savings results for the first year of the MEEIA 2016 programs. As a result of this order and in accordance with revenue recognition guidance, Ameren Missouri recognized $5 million of revenues in the first quarter of 2018 relating to the MEEIA 2016 performance incentive.

In July 2018, the Missouri Supreme Court overturned a 2016 decision by the Missouri Court of Appeals, Western District, which had upheld a 2015 MoPSC order regarding the determination of a certain input used to calculate the MEEIA 2013 performance incentive, and remanded the matter to the MoPSC. The MoPSC is required to issue a revised order consistent with the Missouri Supreme Court’s ruling; however, there is no deadline to issue such order. Upon issuance of the order, Ameren Missouri expects to recognize an additional $9 million MEEIA 2013 performance incentive.

Illinois

Electric Distribution Service Rates

In April 2018, Ameren Illinois filed its annual electric distribution service formula rate update to establish the revenue requirement to be used for 2019 rates with the ICC. In July 2018, the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing, recommending an amount comparable to Ameren Illinois’ filing. Pending ICC approval, this update filing will result in a$72 millionincrease in Ameren Illinois’ electric distribution service rates beginning in January 2019.This update reflects an increase to the annual formula rate based on 2017 actual costs and expected net plant additions for 2018 and an increase to include the 2017 revenue requirement reconciliation adjustment. It also includes a decrease for the conclusion of the 2016 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2018, consistent with the ICC’s December 2017 annual update filing order. An ICC decision in this proceeding is expected by December 2018. As of June 30, 2018, Ameren Illinois had recorded a regulatory asset of $62 million to reflect the difference between Ameren Illinois’ estimate of its 2018 revenue requirement and the revenue requirement reflected in customer rates, including interest.

Electric Customer Energy-Efficiency Investments

In June 2018, Ameren Illinois filed its annual electric customer energy-efficiency formula rate update to establish the revenue requirement to be used for 2019 rates with the ICC. Pending ICC approval, this update filing will result in 2019 rates for electric customer energy-efficiency investments of $34 million, which represents an increase of $20 million from the 2018 rates. An ICC decision regarding the revenue requirement to be used for customer rates in 2019 is expected by December 2018.

Income Tax Regulatory Mechanisms

In February 2018, the ICC granted Ameren Illinois’ request, filed in January 2018, to establish a rider to reduce Ameren Illinois’ electric distribution customer rates for the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA and the return of excess deferred taxes, net of the increase in state income taxes enacted in July 2017. Ameren Illinois' electric distribution customer rates were reduced as a result of the rider beginning in the first quarter of 2018. The estimated reduction of $50 million per year will continue through 2019, as base rates will reflect the current income tax rates starting in 2020.

In April 2018, the ICC approved a rider for the difference between revenues billed under natural gas rates established pursuant to Ameren Illinois’ most recent natural gas rate order, and the revenues that would have been billed had the state and federal tax rate changes discussed above been in effect. The rider required Ameren Illinois to record this regulatory liability beginning January 25, 2018. Ameren Illinois’ natural gas customer rates were reduced as a result of the rider beginning in May 2018, with an estimated reduction of up to $17 million, substantially over a one-year period.

2018 Natural Gas Delivery Service Regulatory Rate Review

In January 2018, Ameren Illinois filed a request with the ICC seeking approval to increase its annual rates for natural gas delivery service. In July 2018, Ameren Illinois and the ICC staff filed a stipulation and agreement with the ICC that, pending ICC approval, would result in an annual natural gas rate increase of $37 million, based on the terms of the agreement and subject to adjustments for updated rate case and other postretirement benefit expenses. This increase in annual rates includes a 9.87% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion. It also reflects the reduction in the federal corporate income tax rate as a result of the TCJA, as well as the increase in the Illinois corporate income tax rate that became effective in July 2017, which decreased the annual rates by approximately $17 million. In an attempt to reduce regulatory lag, Ameren Illinois used a 2019 future test year in this proceeding.

A decision by the ICC in this proceeding is required by December 2018, with new rates expected to be effective in January 2019. Ameren Illinois cannot predict the level of any delivery service rate changes the ICC may approve, nor whether any rate changes that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and to earn a reasonable return on investments when the rate changes go into effect.

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 2016, the FERC issued a final order in the November 2013 complaint case, which lowered the allowed base return on common equity to 10.32%, or a 10.82% total allowed return on common equity with the inclusion of a 50 basis point incentive adder for participation in an RTO, effective since September 2016. The 10.82% allowed return on common equity may be replaced prospectively after the FERC issues a final order in the February 2015 complaint case, discussed below.

Since 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. MISO transmission owners subsequently filed a motion to dismiss the February 2015 complaint, as discussed below. The February 2015 complaint case seeks a further reduction in the allowed base return on common equity for 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. If approved by the FERC, it 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 a 50 basis point incentive adder for participation in an RTO. It would also require customer refunds, with interest, for that 15-month period. A final FERC order would also establish the allowed return on common equity that will apply prospectively from the effective date of such order, replacing the current 10.82% total return on common equity. In the second quarter of 2017, the United States Court of Appeals for the District of Columbia Circuit 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 the FERC is under no deadline to issue a final order, the timing of the issuance of the final order in the February 2015 complaint case is uncertain.

In September 2017, MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed a motion to dismiss the February 2015 complaint case with the FERC. The MISO transmission owners maintain that the February 2015 complaint was predicated on the now superseded 12.38% allowed base return on common equity and is therefore inapplicable given the current 10.32% allowed base return on common equity. The MISO transmission owners further maintain that the current 10.32% allowed base return on common equity has not been proven to be unjust and unreasonable based on information provided, including the base return on common equity methodology ranges set forth in the February 2015 complaint case and in the initial decision issued by an administrative law judge in June 2016. Additionally, the MISO transmission owners maintain that the February 2015 complaint should be dismissed because the approach utilized in the case to assert that a return on common equity was unjust and unreasonable was insufficient. That same approach was rejected by the United States Court of Appeals for the District of Columbia Circuit, as discussed above. The FERC is under no deadline to issue an order on this motion.

As of June 30, 2018, Ameren and Ameren Illinois had recorded current regulatory liabilities of $43 million and $25 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.

FERC Federal Income Tax Proceeding and Formula Rate Change

In March 2018, the FERC granted a request filed in February 2018 by MISO transmission owners with forward-looking rate formulas, including Ameren Illinois and ATXI, to allow revisions to their 2018 electric transmission rates to reflect the effect of the reduction in federal income taxes enacted under the TCJA. Ameren Illinois and ATXI’s 2018 electric transmission rates have been reduced by $27 million and $23 million, respectively.

In May 2018, the FERC accepted Ameren Illinois and ATXI tariff filings to change the formula rate calculation. The change allows for the recovery or refund of both excess deferred income taxes resulting from tax law or rate changes and effect of permanent income tax differences and will be reflected in Ameren Illinois and ATXI’s electric transmission rates starting in January 2019.

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Short-Term Debt And Liquidity

6 Months Ended

Jun. 30, 2018

Debt Disclosure [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 affiliate 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 six months ended June 30, 2018, but were used to support commercial paper issuances and to issue letters of credit. Based on commercial paper outstanding, letters of credit issued under the Credit Agreements, and cash on hand, the aggregate credit capacity available under the Credit Agreements to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, at June 30, 2018, was $1.6 billion. The Ameren Companies were in compliance with the covenants in their Credit Agreements as of June 30, 2018. As of June 30, 2018, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the provisions of the Credit Agreements, were 54%, 48%, and 47% for Ameren, Ameren Missouri, and Ameren Illinois, respectively.

Commercial Paper

The following table presents commercial paper outstanding, net of issuance discounts, as of June 30, 2018, and December 31, 2017:

	2018		2017
Ameren (parent)	$	506	$	383
Ameren Missouri	—		39
Ameren Illinois	—		62
Ameren Consolidated	$	506	$	484

The following table summarizes the borrowing activity and relevant interest rates under Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs for the six months ended June 30, 2018 and 2017:

	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated
2018
Average daily commercial paper outstanding at par value	$	397		$	123		$	174		$	693
Weighted-average interest rate	2.14		%	1.94		%	2.20		%	2.12		%
Peak commercial paper during period at par value(a)	$	506		$	481		$	442		$	1,295
Peak interest rate	2.45		%	2.42		%	2.55		%	2.55		%
2017
Average daily commercial paper outstanding at par value	$	736		$	6		$	66		$	808
Weighted-average interest rate	1.19		%	1.10		%	1.14		%	1.19		%
Peak commercial paper during period at par value(a)	$	841		$	60		$	163		$	948
Peak interest rate	1.50		%	1.41		%	1.50		%	1.50		%

(a) The timing of peak outstanding commercial paper issuances varies by company. Therefore, the sum of individual company peak amounts may 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 borrowings under the money pool for the three and six months ended June 30, 2018, was 2.17% and 2.04%, respectively (2017 – 1.27% and 1.14%, respectively). See Note 8 – Related-party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three and six months ended June 30, 2018 and 2017.

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Long-Term Debt And Equity Financings

6 Months Ended

Jun. 30, 2018

Long-Term Debt And Equity Financings [Abstract]

LONG-TERM DEBT AND EQUITY FINANCINGS

LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

For the three and six months ended June 30, 2018, Ameren issued a total of 0.4 million and 0.7 million shares, respectively, of common stock under its DRPlus and 401(k) plan and received proceeds of $23 million and $40 million, respectively. In addition, in the first quarter of 2018, Ameren issued 0.7 million shares of common stock valued at $35 million upon the vesting of stock-based compensation. Ameren did not issue any common stock during the first six months of 2017.

Ameren Missouri

In April 2018, Ameren Missouri issued $425 million of 4.00% first mortgage bonds due April 2048, with interest payable semiannually on April 1 and October 1 of each year, beginning October 1, 2018. Ameren Missouri received proceeds of $419 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Missouri incurred in connection with the repayment of $179 million of its 6.00% senior secured notes that matured April 1, 2018.

Ameren Illinois

In May 2018, Ameren Illinois issued $430 million of 3.80% first mortgage bonds due May 2028, with interest payable semiannually on May 15 and November 15 of each year, beginning November 15, 2018. Ameren Illinois received proceeds of $427 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Illinois incurred in connection with the repayment of $144 million of its 6.25% senior secured notes that matured April 1, 2018.

Indenture Provisions and Other Covenants

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. At June 30, 2018, the Ameren Companies were in compliance with the provisions and covenants contained in their indentures and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement.

Off-balance-sheet Arrangements

At June 30, 2018, none of the Ameren Companies had any significant 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.

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Other Income and Expenses

6 Months Ended

Jun. 30, 2018

Other Nonoperating Income (Expense) [Abstract]

OTHER INCOME AND EXPENSES

OTHER INCOME, NET

The following table presents the components of “Other Income, Net” in the Ameren Companies’ statements of income for the three and six months ended June 30, 2018 and 2017:

	Three Months							Six Months
	2018				2017			2018				2017
Ameren:(a)
Other Income, Net
Allowance for equity funds used during construction	$	9			$	4		$	14			$	10
Interest income on industrial development revenue bonds	7				6			13				13
Other interest income	2				3			4				5
Non-service cost components of net periodic benefit income	19			(b)	10			35			(b)	22
Other income	2				2			3				2
Donations	(6		)		(2		)	(11		)		(7		)
Other expense	(4		)		(3		)	(6		)		(7		)
Total Other Income, Net	$	29			$	20		$	52			$	38
Ameren Missouri:
Other Income, Net
Allowance for equity funds used during construction	$	7			$	4		$	11			$	9
Interest income on industrial development revenue bonds	7				6			13				13
Other interest income	1				1			1				1
Non-service cost components of net periodic benefit income	4			(b)	6			9			(b)	12
Other income	—				1			1				1
Donations	(2		)		(2		)	(3		)		(2		)
Other expense	(1		)		—			(3		)		(2		)
Total Other Income, Net	$	16			$	16		$	29			$	32
Ameren Illinois:
Other Income, Net
Allowance for equity funds used during construction	$	2			$	—		$	3			$	1
Interest income	1				2			3				4
Non-service cost components of net periodic benefit income	10				1			17				4
Other income	2				2			2				2
Donations	(1		)		(1		)	(5		)		(5		)
Other expense	(1		)		(1		)	(1		)		(3		)
Total Other Income, Net	$	13			$	3		$	19			$	3

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

(b) For the three and six months ended June 30, 2018, the non-service cost components of net periodic benefit income were partially offset by a $4 million and $8 million deferral due to a regulatory tracking mechanism for the difference between the level of such costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates.

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Financial Instruments

6 Months Ended

Jun. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE FINANCIAL INSTRUMENTS

DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives to manage the risk of changes in market prices for natural gas and power, 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 inventories that differ from the cost of those commodities in inventory; and

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

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

The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of June 30, 2018, and December 31, 2017. As of June 30, 2018, these contracts extended through October 2021, March 2023, and May 2032 for fuel oils, natural gas, and power, respectively.

	Quantity (in millions, except as indicated)
	2018			2017
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)(a)	40	(b)	40	28	(b)	28
Natural gas (in mmbtu)	23	149	172	24	139	163
Power (in megawatthours)	2	8	10	3	9	12

(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 June 30, 2018, and December 31, 2017, 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 June 30, 2018, and December 31, 2017:

	Balance Sheet Location	Ameren Missouri		Ameren Illinois		Ameren
2018
Fuel oils	Other current assets	$	8	$	—	$	8
	Other assets	5		—		5
Natural gas	Other current assets	—		1		1
	Other assets	—		1		1
Power	Other current assets	7		—		7
	Total assets (a)	$	20	$	2	$	22
Fuel oils	Other deferred credits and liabilities	$	1	$	—	$	1
Natural gas	Other current liabilities	4		12		16
	Other deferred credits and liabilities	3		13		16
Power	Other current liabilities	2		13		15
	Other deferred credits and liabilities	—		177		177
	Total liabilities (b)	$	10	$	215	$	225
2017
Fuel oils	Other current assets	$	5	$	—	$	5
	Other assets	2		—		2
Natural gas	Other assets	1		—		1
Power	Other current assets	9		—		9
	Total assets (a)	$	17	$	—	$	17
Natural gas	Other current liabilities	$	5	$	12	$	17
	Other deferred credits and liabilities	3		10		13
Power	Other current liabilities	1		13		14
	Other deferred credits and liabilities	—		182		182
	Total liabilities (b)	$	9	$	217	$	226

(a) The cumulative amount of pretax net gains on all derivative instruments is deferred as a regulatory liability.

(b) 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 June 30, 2018, and December 31, 2017.

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 June 30, 2018, if all counterparties were to fail 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 June 30, 2018, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that counterparties could require. The additional collateral required is the net liability position allowed under the master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered on June 30, 2018, 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)
Ameren Missouri	$	63	$	4	$	52
Ameren Illinois	52		—		47
Ameren	$	115	$	4	$	99

(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

6 Months Ended

Jun. 30, 2018

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.

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). We have also 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 three and six months ended June 30, 2018 or 2017. At June 30, 2018, and December 31, 2017, the counterparty default risk valuation adjustment related to derivative contracts was immaterial for Ameren, Ameren Missouri, and Ameren Illinois.

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of June 30, 2018:

		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	$	8	$	—	$	5	$	13
	Natural gas	—		1		1		2
	Power	—		—		7		7
	Total derivative assets – commodity contracts	$	8	$	1	$	13	$	22
	Nuclear decommissioning trust fund:
	Equity securities:
	U.S. large capitalization	$	481	$	—	$	—	$	481
	Debt securities:
	U.S. Treasury and agency securities	—		118		—		118
	Corporate bonds	—		78		—		78
	Other	—		31		—		31
	Total nuclear decommissioning trust fund	$	481	$	227	$	—	$	708	(b)
	Total Ameren	$	489	$	228	$	13	$	730
Ameren Missouri	Derivative assets – commodity contracts(a):
	Fuel oils	$	8	$	—	$	5	$	13
	Power	—		—		7		7
	Total derivative assets – commodity contracts	$	8	$	—	$	12	$	20
	Nuclear decommissioning trust fund:
	Equity securities:
	U.S. large capitalization	$	481	$	—	$	—	$	481
	Debt securities:
	U.S. Treasury and agency securities	—		118		—		118
	Corporate bonds	—		78		—		78
	Other	—		31		—		31
	Total nuclear decommissioning trust fund	$	481	$	227	$	—	$	708	(b)
	Total Ameren Missouri	$	489	$	227	$	12	$	728
Ameren Illinois	Derivative assets – commodity contracts(a):
	Natural gas	$	—	$	1	$	1	$	2
Liabilities:
Ameren	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	—	$	—	$	1	$	1
	Natural gas	1		26		5		32
	Power	—		—		192		192
	Total Ameren	$	1	$	26	$	198	$	225
Ameren Missouri	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	—	$	—	$	1	$	1
	Natural gas			7		—		7
	Power	—		—		2		2
	Total Ameren Missouri	$	—	$	7	$	3	$	10
Ameren Illinois	Derivative liabilities – commodity contracts(a):
	Natural gas	$	1	$	19	$	5	$	25
	Power	—		—		190		190
	Total Ameren Illinois	$	1	$	19	$	195	$	215

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

(b) Balance excludes $6 million of cash and cash equivalents, 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, 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	$	4	$	—	$	3	$	7
	Natural gas	—		—		1		1
	Power	—		1		8		9
	Total derivative assets – commodity contracts	$	4	$	1	$	12	$	17
	Nuclear decommissioning trust fund:
	Equity securities:
	U.S. large capitalization	$	468	$	—	$	—	$	468
	Debt securities:
	U.S. Treasury and agency securities	—		125		—		125
	Corporate bonds	—		82		—		82
	Other	—		25		—		25
	Total nuclear decommissioning trust fund	$	468	$	232	$	—	$	700	(b)
	Total Ameren	$	472	$	233	$	12	$	717
Ameren Missouri	Derivative assets – commodity contracts(a):
	Fuel oils	$	4	$	—	$	3	$	7
	Natural gas	—		—		1		1
	Power	—		1		8		9
	Total derivative assets – commodity contracts	$	4	$	1	$	12	$	17
	Nuclear decommissioning trust fund:
	Equity securities:
	U.S. large capitalization	$	468	$	—	$	—	$	468
	Debt securities:
	U.S. Treasury and agency securities	—		125		—		125
	Corporate bonds	—		82		—		82
	Other	—		25		—		25
	Total nuclear decommissioning trust fund	$	468	$	232	$	—	$	700	(b)
	Total Ameren Missouri	$	472	$	233	$	12	$	717
Liabilities:
Ameren	Derivative liabilities – commodity contracts(a):
	Natural gas	$	1	$	25	$	4	$	30
	Power	—		—		196		196
	Total Ameren	$	1	$	25	$	200	$	226
Ameren Missouri	Derivative liabilities – commodity contracts(a):
	Natural gas	$	—	$	7	$	1	$	8
	Power	—		—		1		1
	Total Ameren Missouri	$	—	$	7	$	2	$	9
Ameren Illinois	Derivative liabilities – commodity contracts(a):
	Natural gas	$	1	$	18	$	3	$	22
	Power	—		—		195		195
	Total Ameren Illinois	$	1	$	18	$	198	$	217

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

(b) Balance excludes $4 million of cash and cash equivalents, 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 and six months ended June 30, 2018 and 2017, the balances and changes in the fair value of Level 3 financial assets and liabilities associated with fuel oils and natural gas 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 June 30, 2018
Beginning balance at April 1, 2018	$	4		$	(191	)	$	(187	)
Realized and unrealized losses included in regulatory assets/liabilities		(1	)		(2	)		(3	)
Purchases		4			—			4
Settlements		(2	)		3			1
Ending balance at June 30, 2018	$	5		$	(190	)	$	(185	)
Change in unrealized losses related to assets/liabilities held at June 30, 2018	$	—		$	(3	)	$	(3	)
For the three months ended June 30, 2017
Beginning balance at April 1, 2017	$	4		$	(194	)	$	(190	)
Realized and unrealized losses included in regulatory assets/liabilities		(1	)		(1	)		(2	)
Purchases		15			—			15
Settlements		(4	)		3			(1	)
Ending balance at June 30, 2017	$	14		$	(192	)	$	(178	)
Change in unrealized losses related to assets/liabilities held at June 30, 2017	$	—		$	(2	)	$	(2	)
For the six months ended June 30, 2018
Beginning balance at January 1, 2018	$	7		$	(195	)	$	(188	)
Realized and unrealized losses included in regulatory assets/liabilities		(3	)		(1	)		(4	)
Purchases		4			—			4
Settlements		(3	)		6			3
Ending balance at June 30, 2018	$	5		$	(190	)	$	(185	)
Change in unrealized losses related to assets/liabilities held at June 30, 2018	$	(1	)	$	(2	)	$	(3	)
For the six months ended June 30, 2017
Beginning balance at January 1, 2017	$	7		$	(185	)	$	(178	)
Realized and unrealized losses included in regulatory assets/liabilities		(1	)		(11	)		(12	)
Purchases		15			—			15
Settlements		(7	)		4			(3	)
Ending balance at June 30, 2017	$	14		$	(192	)	$	(178	)
Change in unrealized losses related to assets/liabilities held at June 30, 2017	$	—		$	(13	)	$	(13	)

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 and six months ended June 30, 2018 and 2017, 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 following table describes the valuation techniques and unobservable inputs utilized by the Ameren Companies for the fair value of financial assets and liabilities measured at fair value on a recurring basis and classified as Level 3 in the fair value hierarchy for the periods ended June 30, 2018, and December 31, 2017:

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
Level 3 Derivative asset and liability – commodity contracts(a):
2018
	Fuel oils	$	5	$	(1	)	Option model	Volatilities(%)(b)	20 – 34	25
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.12 – 0.85	0.38
								Ameren Missouri credit risk(%)(c)(d)	0.35	(e)
	Natural gas	1		(5		)	Discounted cash flow	Nodal basis ($/mmbtu)(b)	(1.30) – 0.30	(0.90)
								Counterparty credit risk (%)(c)(d)	0.23 – 1	0.81
								Ameren Illinois credit risk (%)(c)(d)	0.35	(e)
	Power(f)	7		(192		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)(g)	24 – 39	27
								Estimated auction price for FTRs ($/MW)(b)	(898) – 1,180	57
								Nodal basis ($/MWh)(g)	(10) – 0	(2)
								Counterparty credit risk (%)(c)(d)	0.91	(e)
								Ameren Illinois credit risk (%)(c)(d)	0.35	(e)
							Fundamental energy production model	Estimated future natural gas prices ($/mmbtu)(b)	3	(e)
								Escalation rate (%)(b)(h)	4	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(b)	5 – 7	6
2017
	Fuel oils	$	3	$	—		Option model	Volatilities (%)(b)	20 – 26	22
							Discounted cash flow	Counterparty credit risk (%)(c)(d)	0.12 – 0.72	0.41
								Ameren Missouri credit risk (%)(c)(d)	0.37	(e)
	Natural gas	1		(4		)	Option model	Volatilities (%)(b)	26 – 46	37
								Nodal basis ($/mmbtu)(c)	(0.50) – (0.30)	(0.40)
							Discounted cash flow	Nodal basis ($/mmbtu)(b)	(1.20) – 0.10	(1)
								Counterparty credit risk (%)(c)(d)	0.37 – 0.92	0.53
								Ameren credit risk (%)(c)(d)	0.37	(e)
	Power(f)	8		(196		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)(g)	24 – 46	28
								Estimated auction price for FTRs ($/MW)(b)	(65) – 1,823	251
								Nodal basis ($/MWh)(g)	(10) – 0	(2)
								Counterparty credit risk (%)(c)(d)	0.28	(e)
								Ameren Illinois credit risk (%)(c)(d)	0.37	(e)
							Fundamental energy production model	Estimated future natural gas prices ($/mmbtu)(b)	3 – 4	3
								Escalation rate (%)(b)(h)	5	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(b)	5 – 7	6

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

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

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

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

(e) Not applicable.

(f) Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2022 for June 30, 2018, and through 2021 for December 31, 2017. Valuations beyond 2022 for June 30, 2018, and 2021 for December 31, 2017, use fundamentally modeled pricing by month for peak and off-peak demand.

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

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

The following table sets forth, by level within the fair value hierarchy, the carrying amount and fair value of financial assets and liabilities disclosed, but not carried, at fair value as of June 30, 2018, and December 31, 2017:

	June 30, 2018
	Carrying Amount			Fair Value
				Level 1		Level 2		Level 3			Total
Ameren:
Cash, cash equivalents, and restricted cash	$	96		$	96	$	—	$	—		$	96
Investments in held-to-maturity debt securities(a)	276			—		276		—			276
Short-term debt	506			—		506		—			506
Long-term debt (including current portion)(a)	8,460		(b)	—		8,411		438		(c)	8,849
Preferred stock(d)	142			—		140		—			140
Ameren Missouri:
Cash, cash equivalents, and restricted cash	$	25		$	25	$	—	$	—		$	25
Advances to money pool	66			—		66		—			66
Investments in held-to-maturity debt securities(a)	276			—		276		—			276
Long-term debt (including current portion)(a)	4,202		(b)	—		4,544		—			4,544
Preferred stock	80			—		79		—			79
Ameren Illinois:
Cash, cash equivalents, and restricted cash	$	57		$	57	$	—	$	—		$	57
Borrowings from money pool	31			—		31		—			31
Long-term debt (including current portion)	3,113		(b)	—		3,187		—			3,187
Preferred stock	62			—		61		—			61
	December 31, 2017
Ameren:
Cash, cash equivalents, and restricted cash	$	68		$	68	$	—	$	—		$	68
Investments in held-to-maturity debt securities(a)	276			—		276		—			276
Short-term debt	484			—		484		—			484
Long-term debt (including current portion)(a)	7,935		(b)	—		8,531		—			8,531
Preferred stock(c)	142			—		131		—			131
Ameren Missouri:
Cash, cash equivalents, and restricted cash	$	7		$	7	$	—	$	—		$	7
Investments in held-to-maturity debt securities(a)	276			—		276		—			276
Short-term debt	39			—		39		—			39
Long-term debt (including current portion)(a)	3,961		(b)	—		4,348		—			4,348
Preferred stock	80			—		80		—			80
Ameren Illinois:
Cash, cash equivalents, and restricted cash	$	41		$	41	$	—	$	—		$	41
Short-term debt	62			—		62		—			62
Long-term debt (including current portion)	2,830		(b)	—		3,028		—			3,028
Preferred stock	62			—		51		—			51

(a) Ameren and Ameren Missouri have investments in industrial revenue bonds, classified as held-to-maturity and recorded in “Other Assets,” that are equal to the capital lease obligation for CTs leased from the city of Bowling Green and Audrain County. As of June 30, 2018, and December 31, 2017, the carrying amount of both the investments in industrial revenue bonds and the capital lease obligations approximated fair value.

(b) Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $56 million, $23 million, and $27 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of June 30, 2018. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $50 million, $20 million, and $24 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2017.

(c) The Level 3 fair value amount consists of ATXI’s senior unsecured notes. In the first quarter of 2018, the amount was transferred to Level 3 because inputs to the valuation model became unobservable during the period.

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

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Related Party Transactions

6 Months Ended

Jun. 30, 2018

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 natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between Ameren’s subsidiaries are reported as affiliate transactions on their individual financial statements, but those transactions are eliminated in consolidation for Ameren’s consolidated financial statements. For a discussion of our material related-party agreements and money pool arrangements, see Note 13 – Related-party Transactions and Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of the Form 10-K.

Electric Power Supply Agreement

In April 2018, 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 2018, Ameren Missouri and Ameren Illinois entered into an energy product agreement by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, 110,000 megawatthours at an average price of $32 per megawatthour during the period of June 2019 through September 2020.

The following table presents the impact on Ameren Missouri and Ameren Illinois of related-party transactions for the three and six months ended June 30, 2018 and 2017:

				Three Months				Six Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2018	$	3	$	(a)	$	6	$	(a)
agreements with Ameren Illinois		2017		6		(a)		17		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2018		6		1		11		2
rent and facility services		2017		6		1		13		2
Ameren Missouri and Ameren Illinois	Operating Revenues	2018		(b)		(b)		(b)		(b)
miscellaneous support services		2017		(b)		1		(b)		1
Total Operating Revenues		2018	$	9	$	1	$	17	$	2
		2017		12		2		30		3
Ameren Illinois power supply	Purchased Power	2018	$	(a)	$	3	$	(a)	$	6
agreements with Ameren Missouri		2017		(a)		6		(a)		17
Ameren Illinois transmission	Purchased Power	2018		(a)		1		(a)		1
services with ATXI		2017		(a)		1		(a)		1
Total Purchased Power		2018	$	(a)	$	4	$	(a)	$	7
		2017		(a)		7		(a)		18
Ameren Services support services	Other Operations and Maintenance	2018	$	32	$	30	$	65	$	60
agreement		2017		34		34		69		66
Money pool borrowings (advances)	Interest Charges/ Other Income, Net	2018	$	(b)	$	(b)	$	(b)	$	(b)
		2017		(b)		(b)		(b)		(b)

(a) Not applicable.

(b) Amount less than $1 million.

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Commitments And Contingencies

6 Months Ended

Jun. 30, 2018

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 the 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 13 – Related-party Transactions, and Note 14 – Commitments and Contingencies under Part II, Item 8, of the Form 10-K. See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 8 – Related-party Transactions, and Note 10 – Callaway Energy Center of this report.

Other Obligations

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. Ameren Missouri and Ameren Illinois also have entered into various long-term commitments for purchased power and natural gas for distribution. The table below presents our estimated minimum fuel, purchased power, and other commitments for fuel at June 30, 2018. Ameren’s and Ameren Illinois’ purchased power commitments include the Ameren Illinois agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services, among other agreements, at June 30, 2018.

	Coal		Natural Gas(a)		Nuclear Fuel		Purchased Power(b)(c)		Methane Gas		Other		Total
Ameren:(d)
2018	$	181	$	148	$	51	$	130	$	2	$	56	$	568
2019	246		210		27		122		4		47		656
2020	85		125		38		30		4		62		344
2021	27		61		57		5		5		28		183
2022	—		12		12		—		5		26		55
Thereafter	—		39		62		—		58		93		252
Total	$	539	$	595	$	247	$	287	$	78	$	312	$	2,058
Ameren Missouri:
2018	$	181	$	22	$	51	$	—	$	2	$	39	$	295
2019	246		38		27		—		4		29		344
2020	85		30		38		—		4		44		201
2021	27		14		57		—		5		25		128
2022	—		5		12		—		5		26		48
Thereafter	—		17		62		—		58		74		211
Total	$	539	$	126	$	247	$	—	$	78	$	237	$	1,227
Ameren Illinois:
2018	$	—	$	126	$	—	$	130	$	—	$	5	$	261
2019	—		172		—		122		—		9		303
2020	—		95		—		30		—		9		134
2021	—		47		—		5		—		—		52
2022	—		7		—		—		—		—		7
Thereafter	—		22		—		—		—		—		22
Total	$	—	$	469	$	—	$	287	$	—	$	23	$	779

(a) Includes amounts for generation and for distribution.

(b) The purchased power amounts for Ameren and Ameren Illinois exclude agreements for renewable energy credits through 2032 with various renewable energy suppliers due to the contingent nature of the payment amounts.

(c) The purchased power amounts for Ameren and Ameren Missouri exclude a 102-megawatt power purchase agreement with a wind farm operator, which expires in 2024, due to the contingent nature of the payment amounts.

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

In January 2018, as required by the FEJA, Ameren Illinois entered into 10-year agreements to acquire zero emission credits. Annual zero emission credit commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. The amounts above reflect Ameren Illinois’ commitment to acquire zero emission credits of approximately $57 million through May 2019.

In April 2018, Ameren Illinois conducted procurement events, administered by the IPA, to purchase energy products through May 2021. In the April 2018 procurement event, Ameren Illinois contracted to purchase 3,956,200 megawatthours of energy products for $112 million from June 2018 through May 2021, which is reflected in the amounts above. See Note 8 – Related-party Transactions for additional information regarding energy product agreements between Ameren Missouri and Ameren Illinois as a result of the April 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 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, 2017, Ameren Missouri’s fossil fuel-fired energy centers represented 17% and 33% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations that apply to air emissions from the electric utility industry include the NSPS, the CSAPR, the MATS, and the 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, and CO₂ emissions from new power plants. Water intake and discharges from power plants are regulated under the Clean Water Act. Such regulation could require modifications to water intake structures or more stringent limitations on wastewater discharges at Ameren Missouri’s energy centers, either of which could result in significant capital expenditures. The management and disposal of coal ash is regulated under the CCR Rule, which will require the closure of surface impoundments and the installations of dry ash handling systems at several of Ameren Missouri’s energy centers. The individual or combined effects of existing environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers. 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 air emission regulations 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 $325 million to $425 million from 2018 through 2022 in order to comply with existing environmental regulations. Additional environmental controls beyond 2022 could be required. This estimate of capital expenditures includes expenditures required by the CCR regulations, by the Clean Water Act rule applicable to cooling water intake structures at existing power plants, and by effluent limitation guidelines applicable to steam electric generating units, all of which are 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 substantially revise regulatory obligations, exactly which compliance strategies will be used and their ultimate cost, among other things.

The following sections describe the more significant environmental laws and rules and environmental enforcement and remediation matters that affect or could affect our operations. The EPA has initiated an administrative review of several regulations and proposed regulation amendments, including to the effluent limitation guidelines and the CCR Rule, which could ultimately result in the revision of all or part of such rules.

Clean Air Act

Federal and state laws, including CSAPR, regulate emissions of SO₂ and NO_x through emission source reductions and 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 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 the Clean Power Plan, which would have established CO₂ emissions standards applicable to existing power plants. The United States Supreme Court stayed the rule in February 2016, pending various legal challenges. In July 2018, the Office of Management and Budget received the EPA’s proposal to repeal and replace the Clean Power Plan. We expect that the EPA's Clean Power Plan replacement rule, including anticipated future emissions regulation, will be released and made publicly available later this year following the Office of Management and Budget’s review. We cannot predict the outcome of EPA’s rulemaking or the outcome of legal challenges related to such future rulemakings.

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 then proceeded to the second phase to determine the actions required to remedy the violations found in the liability phase. The EPA previously withdrew all claims for penalties and fines. No date has been set by the district court for a trial on the remedy phase of the litigation. At the conclusion of both phases of the litigation, Ameren Missouri intends to appeal the liability ruling to the United States Court of Appeals for the Eighth Circuit.

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 July 2018, the United States Court of Appeals for the Second Circuit upheld the EPA’s Section 316(b) 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. The rule will be implemented between 2018 and 2023, during the permit renewal process of each energy center’s water discharge permit.

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 September 2017, the EPA published a rule that postponed the compliance dates by two years for the limitations applicable to two specific waste streams so that it could potentially revise those standards. Ameren Missouri is in the process of constructing wastewater treatment facilities at three of its energy centers. The cost to complete these facilities is included in the capital expenditures, discussed above, that Ameren and Ameren Missouri estimate they will need to make in order to comply with existing environmental regulations.

CCR Management

In 2015, the EPA issued the CCR Rule, which established 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. In July 2018, the EPA issued revisions to the CCR Rule that extended certain compliance deadlines and indicated that additional revisions to the CCR Rule are likely. Ameren and Ameren Missouri have AROs of $141 million recorded on their respective balance sheets as of June 30, 2018, associated with CCR storage facilities that reflect the regulations issued in 2015. Ameren plans to close these CCR storage facilities between 2018 and 2023. The recent EPA revisions do not affect Ameren Missouri’s plan. Ameren Missouri estimates it will need to make capital expenditures of $300 million to $350 million from 2018 through 2022 to implement its CCR management compliance plan, which includes installation of dry ash handling systems, waste water treatment facilities, and groundwater monitoring equipment.

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 June 30, 2018, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois, the majority of which have been investigated, remediated, and closed. Ameren Illinois estimates it could substantially conclude remediation efforts by 2023. The ICC allows Ameren Illinois to recover such remediation and related litigation costs from its electric and natural gas utility customers through environmental cost riders. Costs are subject to annual prudence review by the ICC. As of June 30, 2018, Ameren Illinois estimated the obligation related to these former MGP sites at $165 million to $236 million. Ameren and Ameren Illinois recorded a liability of $165 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, technical feasibility of certain remediation measures, regulatory changes, disposal costs, and site accessibility. The actual costs and timing of completion 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. 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. Ameren Missouri is the owner of one of the sites and in July 2018 reached an agreement with the EPA and Solutia, Inc., the primary potentially responsible party for Sauget Area 2, which limits Ameren Missouri’s cleanup obligation to the site it owns. Remediation efforts at the site are expected to occur in 2019. As of June 30, 2018, 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.

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Callaway Energy Center

6 Months Ended

Jun. 30, 2018

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 paid by Ameren Missouri and other utilities that own and operate those energy centers to 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 2014.

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. Ameren Missouri’s lawsuit against the DOE resulted in a settlement agreement that provides for annual reimbursement of additional spent fuel storage and related costs. For the six months ended June 30, 2018 and 2017, 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. 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.

Supplier of Fuel Assemblies

The Callaway energy center uses nuclear fuel assemblies fabricated by Westinghouse, which is 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. As part of its bankruptcy plan, Westinghouse filed a schedule of assumed contracts, which includes all current contracts between Westinghouse and Ameren Missouri, including the contract for fabrication of fuel assemblies for the Callaway energy center. In April 2018, the bankruptcy court approved Westinghouse’s bankruptcy plan, which included the assumption of its contracts with Ameren Missouri. The plan is expected to become effective in the third quarter of 2018. At this time, Ameren and Ameren Missouri believe the remainder of 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. 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.

Decommissioning

Electric 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. An updated cost study and funding analysis was filed with the MoPSC in September 2017 and reflected within the ARO. In January 2018, the MoPSC approved no change in electric rates for decommissioning costs based on Ameren Missouri’s updated cost study and funding analysis.

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.

Insurance

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center as of June 30, 2018. 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 2018.

Type and Source of Coverage	Maximum Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	450		$	—
Pool participation	12,604		(a)	127		(b)
	$	13,054	(c)	$	127
Property damage:
NEIL and EMANI	$	3,200	(d)	$	27	(e)
Replacement power:
NEIL	$	490	(f)	$	7	(e)

(a) Provided through mandatory participation in an industrywide retrospective premium assessment program. The maximum coverage available is dependent on the number of United States commercial reactors participating in the 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 insurance for nonradiation events. EMANI provides $490 million in property damage insurance 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

6 Months Ended

Jun. 30, 2018

Defined Benefit Plan [Abstract]

RETIREMENT BENEFITS

RETIREMENT BENEFITS

In March 2017, the FASB issued authoritative guidance that requires an entity to report, including on a retrospective basis, the non-service cost or income components of net periodic benefit cost separately from the service cost component and outside of operating income. The Ameren Companies adopted this guidance, effective January 1, 2018, and as a result, $22 million, $12 million, and $4 million of net benefit income has been retrospectively reclassified from "Operating Expenses – Other operations and maintenance" to “Other Income, Net” on Ameren's, Ameren Missouri's, and Ameren Illinois' respective statements of income for the six months ended June 30, 2017. Net benefit income of $10 million, $6 million, and $1 million has been similarly retrospectively reclassified on Ameren's, Ameren Missouri's, and Ameren Illinois' respective statements of income for the three months ended June 30, 2017.

The guidance also requires an entity to capitalize only 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. This change in the capitalization of net benefit costs is not expected to affect our ability to recover total net benefit cost through customer rates.

The following table presents the components of the net periodic benefit cost (income), prior to capitalization, incurred for Ameren’s pension and postretirement benefit plans for the three and six months ended June 30, 2018 and 2017:

	Pension Benefits												Postretirement Benefits
	Three Months						Six Months						Three Months						Six Months
	2018			2017			2018			2017			2018			2017			2018			2017
Service cost(a)	$	25		$	23		$	50		$	46		$	5		$	5		$	10		$	10
Non-service cost components:
Interest cost	42			45			84			90			9			11			20			23
Expected return on plan assets	(69		)	(65		)	(138		)	(131		)	(19		)	(18		)	(38		)	(37		)
Amortization of:
Prior service benefit	—			—			—			—			(1		)	(1		)	(2		)	(2		)
Actuarial loss (gain)	18			13			34			27			(3		)	(1		)	(3		)	(3		)
Total non-service cost components(b)	(9		)	(7		)	(20		)	(14		)	(14		)	(9		)	(23		)	(19		)
Net periodic benefit cost (income)	$	16		$	16		$	30		$	32		$	(9	)	$	(4	)	$	(13	)	$	(9	)

(a) Service cost, net of capitalization, is reflected in “Operating Expenses – Other operations and maintenance” on Ameren’s statement of income.

(b) 2018 amounts and the non-capitalized portion of 2017’s non-service cost components, as discussed above, are reflected in “Other Income, Net” on Ameren’s statement of income. See Note 5 – Other Income, Net for additional information.

Ameren Missouri and Ameren Illinois are responsible for their respective shares of Ameren’s pension and postretirement costs. The following table presents the respective share of net periodic pension and other postretirement benefit costs (income) incurred for the three and six months ended June 30, 2018 and 2017:

	Pension Benefits								Postretirement Benefits
	Three Months				Six Months				Three Months						Six Months
	2018		2017		2018		2017		2018			2017			2018			2017
Ameren Missouri(a)	$	6	$	6	$	11	$	12	$	—		$	(1	)	$	—		$	(2	)
Ameren Illinois	10		10		19		20		(9		)	(3		)	(13		)	(7		)
Ameren(a)	$	16	$	16	$	30	$	32	$	(9	)	$	(4	)	$	(13	)	$	(9	)

(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.

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Segment Information

6 Months Ended

Jun. 30, 2018

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 primarily comprises the aggregated electric transmission businesses of Ameren Illinois and ATXI. The category called Other primarily includes Ameren (parent) 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, Ameren Illinois, and ATXI.

Segment operating revenues and a majority of operating expenses are directly recognized and incurred by Ameren Illinois at 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, other retail electric suppliers, and wholesale customers. 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 in Ameren Transmission’s and Ameren Illinois Transmission’s operating revenues. An intersegment elimination at Ameren and Ameren Illinois occurs to eliminate these transmission revenues and expenses.

The following tables present revenues, net income attributable to common shareholders, and capital expenditures by segment at Ameren and Ameren Illinois for the three and six months ended June 30, 2018 and 2017. 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
2018
External revenues	$	946	$	386	$	142	$	89		$	—		$	—		$	1,563
Intersegment revenues	9		1		—		14			—			(24		)	—
Net income attributable to Ameren common shareholders	168		33		7		36		(a)	(5		)	—			239
Capital expenditures	205		132		66		130			(2		)	2			533
2017
External revenues	$	922	$	387	$	134	$	92		$	2		$	—		$	1,537
Intersegment revenues	12		2		—		13			—			(27		)	—
Net income attributable to Ameren common shareholders	120		33		5		34		(a)	1			—			193
Capital expenditures	159		122		58		156			1			(2		)	494
Six Months
2018
External revenues	$	1,730	$	785	$	453	$	180		$	—		$	—		$	3,148
Intersegment revenues	17		2		—		27			—			(46		)	—
Net income attributable to Ameren common shareholders	206		66		49		73		(a)	(4		)	—			390
Capital expenditures	454		254		126		275			5			(2		)	1,112
2017
External revenues	$	1,695	$	771	$	398	$	188		$	—		$	—		$	3,052
Intersegment revenues	30		3		—		19			—			(52		)	—
Net income attributable to Ameren common shareholders	125		63		38		68		(a)	1			—			295
Capital expenditures	355		242		109		290			5			(3		)	998

(a) Ameren Transmission earnings include an allocation of financing costs from Ameren (parent).

Ameren Illinois

Three Months	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Intersegment Eliminations			Total Ameren Illinois
2018
External revenues	$	387	$	142	$	49	$	—		$	578
Intersegment revenues	—		—		13		(13		)	—
Net income available to common shareholder	33		7		22		—			62
Capital expenditures	132		66		104		—			302
2017
External revenues	$	389	$	134	$	53	$	—		$	576
Intersegment revenues	—		—		12		(12		)	—
Net income available to common shareholder	33		5		19		—			57
Capital expenditures	122		58		77		—			257
Six Months
2018
External revenues	$	787	$	453	$	98	$	—		$	1,338
Intersegment revenues	—		—		26		(26		)	—
Net income available to common shareholder	66		49		42		—			157
Capital expenditures	254		126		222		—			602
2017
External revenues	$	774	$	398	$	107	$	—		$	1,279
Intersegment revenues	—		—		18		(18		)	—
Net income available to common shareholder	63		38		35		—			136
Capital expenditures	242		109		133		—			484

The following tables present disaggregated revenues by segment at Ameren and Ameren Illinois for the three and six months ended June 30, 2018 and 2017. Economic factors affect the nature, timing, amount, and uncertainty of revenues and cash flows in a similar manner across customer classes. Revenues from alternative revenue programs have a similar distribution among customer classes as revenues from contracts with customers. Other revenues not associated with contracts with customers are presented in the Other customer classification, along with electric transmission and off-system revenues.

Ameren

Three Months	Ameren Missouri				Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission		Other		Intersegment Eliminations			Consolidated
2018
Residential	$	432			$	221	$	—	$	—	$	—	$	—		$	653
Commercial	364				126		—		—		—		—			490
Industrial	87				33		—		—		—		—			120
Other	47			(a)	7		—		103		—		(24		)	133		(a)
Total electric revenues	$	930			$	387	$	—	$	103	$	—	$	(24	)	$	1,396
Residential	$	13			$	—	$	97	$	—	$	—	$	—		$	110
Commercial	6				—		26		—		—		—			32
Industrial	—				—		5		—		—		—			5
Other	6				—		14		—		—		—			20
Total gas revenues	25				—		142		—		—		—			167
Total revenues(b)	$	955			$	387	$	142	$	103	$	—	$	(24	)	$	1,563
2017
Residential	$	358			$	208	$	—	$	—	$	—	$	—		$	566
Commercial	332				129		—		—		—		—			461
Industrial	84				28		—		—		—		—			112
Other	138				24		—		105		2		(26		)	243
Total electric revenues	$	912			$	389	$	—	$	105	$	2	$	(26	)	$	1,382
Residential	$	10			$	—	$	84	$	—	$	—	$	—		$	94
Commercial	4				—		24		—		—		—			28
Industrial	1				—		2		—		—		—			3
Other	7				—		24		—		—		(1		)	30
Total gas revenues	$	22			$	—	$	134	$	—	$	—	$	(1	)	$	155
Total revenues(b)	$	934			$	389	$	134	$	105	$	2	$	(27	)	$	1,537
Six Months
2018
Residential	$	764			$	440	$	—	$	—	$	—	$	—		$	1,204
Commercial	616				250		—		—		—		—			866
Industrial	148				68		—		—		—		—			216
Other	143			(a)	29		—		207		—		(46		)	333		(a)
Total electric revenues	$	1,671			$	787	$	—	$	207	$	—	$	(46	)	$	2,619
Residential	$	54			$	—	$	340	$	—	$	—	$	—		$	394
Commercial	22				—		93		—		—		—			115
Industrial	2				—		11		—		—		—			13
Other	(2		)		—		9		—		—		—			7
Total gas revenues	$	76			$	—	$	453	$	—	$	—	$	—		$	529
Total revenues(b)	$	1,747			$	787	$	453	$	207	$	—	$	(46	)	$	3,148
2017
Residential	$	644			$	427	$	—	$	—	$	—	$	—		$	1,071
Commercial	562				262		—		—		—		—			824
Industrial	142				56		—		—		—		—			198
Other	311				29		—		207		—		(51		)	496
Total electric revenues	$	1,659			$	774	$	—	$	207	$	—	$	(51	)	$	2,589
Residential	$	40			$	—	$	287	$	—	$	—	$	—		$	327
Commercial	16				—		79		—		—		—			95
Industrial	2				—		5		—		—		—			7
Other	8				—		27		—		—		(1		)	34
Total gas revenues	$	66			$	—	$	398	$	—	$	—	$	(1	)	$	463
Total revenues(b)	$	1,725			$	774	$	398	$	207	$	—	$	(52	)	$	3,052

(a) Includes $37 million and $47 million for the three and six months ended June 30, 2018, respectively, for the reduction to revenue for the excess amounts collected in rates related to the TCJA from January 1, 2018, through June 30, 2018. See Note 2 – Rate and Regulatory Matters for additional information.

(b) The following table presents revenues from alternative revenue programs and other revenues not from contracts with customers for the three and six months ended June 30, 2018 and 2017:

Three Months	Ameren Missouri			Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas			Ameren Transmission			Consolidated
2018
Revenues from alternative revenue programs	$	(5	)	$	15	$	(5	)	$	(5	)	$	—
Other revenues not from contracts with customers	5			3		—			—			8
2017
Revenues from alternative revenue programs	$	(7	)	$	16	$	1		$	2		$	12
Other revenues not from contracts with customers	3			1		1			—			5
Six Months
2018
Revenues from alternative revenue programs	$	(9	)	$	46	$	(8	)	$	(9	)	$	20
Other revenues not from contracts with customers	19			13		1			—			33
2017
Revenues from alternative revenue programs	$	(14	)	$	49	$	12		$	7		$	54
Other revenues not from contracts with customers	7			3		2			—			12

Ameren Illinois

Three Months	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Intersegment Eliminations			Total Ameren Illinois
2018
Residential	$	221	$	97	$	—	$	—		$	318
Commercial	126		26		—		—			152
Industrial	33		5		—		—			38
Other	7		14		62		(13		)	70
Total revenues(a)	$	387	$	142	$	62	$	(13	)	$	578
2017
Residential	$	208	$	84	$	—	$	—		$	292
Commercial	129		24		—		—			153
Industrial	28		2		—		—			30
Other	24		24		65		(12		)	101
Total revenues(a)	$	389	$	134	$	65	$	(12	)	$	576
Six Months
2018
Residential	$	440	$	340	$	—	$	—		$	780
Commercial	250		93		—		—			343
Industrial	68		11		—		—			79
Other	29		9		124		(26		)	136
Total revenues(a)	$	787	$	453	$	124	$	(26	)	$	1,338
2017
Residential	$	427	$	287	$	—	$	—		$	714
Commercial	262		79		—		—			341
Industrial	56		5		—		—			61
Other	29		27		125		(18		)	163
Total revenues(a)	$	774	$	398	$	125	$	(18	)	$	1,279

(a) The following table presents revenues from alternative revenue programs and other revenues not from contracts with customers for the Ameren Illinois segments for the three and six months ended June 30, 2018 and 2017:

Three Months	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas			Ameren Illinois Transmission			Consolidated
2018
Revenues from alternative revenue programs	$	15	$	(5	)	$	(5	)	$	5
Other revenues not from contracts with customers	3		—			—			3
2017
Revenues from alternative revenue programs	$	16	$	1		$	2		$	19
Other revenues not from contracts with customers	1		1			—			2
Six Months
2018
Revenues from alternative revenue programs	$	46	$	(8	)	$	(9	)	$	29
Other revenues not from contracts with customers	13		1			—			14
2017
Revenues from alternative revenue programs	$	49	$	12		$	5		$	66
Other revenues not from contracts with customers	3		2			—			5

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Summary Of Significant Accounting Policies (Policies)

3 Months Ended

6 Months Ended

Jun. 30, 2018

Jun. 30, 2018

Accounting Policies [Abstract]

Nature of Operations

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company whose primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Ameren also has other subsidiaries that conduct other activities, such as providing shared services. Ameren evaluates competitive electric transmission investment opportunities 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 and Mark Twain projects, and placed the Spoon River project in service in February 2018.

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.

As of both June 30, 2018, and December 31, 2017, Ameren had unconsolidated variable interests as a limited partner in various equity method investments, totaling $17 million, included in “Other assets” on Ameren’s consolidated balance sheet. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly affect the activities of these variable interest entities. As of June 30, 2018, the maximum exposure to loss related to these variable interests is limited to the investment in these partnerships of $17 million plus associated outstanding funding commitments of $19 million.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and accompanying notes included in the Form 10-K.

Cash and Cash Equivalents, Policy

Cash, Cash Equivalents, and Restricted Cash

Cash and cash equivalents include short-term, highly liquid investments purchased with an original maturity of three months or less. Cash and cash equivalents subject to legal or contractual restrictions and not readily available for use for general corporate purposes are classified as restricted cash.

In November 2016, the FASB issued authoritative guidance that requires, including on a retrospective basis, restricted cash to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Our adoption of this guidance, effective January 2018, did not result in material changes to previously reported cash flows from operating, investing, or financing activities.

Life Insurance, Corporate or Bank Owned

Company-owned Life Insurance

Ameren and Ameren Illinois have company-owned life insurance, which is recorded at the net cash surrender value. The net cash surrender value is the amount that can be realized under the insurance policies at the balance sheet date. As of June 30, 2018, the cash surrender value of company-owned life insurance at Ameren and Ameren Illinois was $249 million (December 31, 2017 – $265 million) and $117 million (December 31, 2017 – $129 million), respectively, while total borrowings against the policies were $107 million (December 31, 2017 – $120 million) at both Ameren and Ameren Illinois. Ameren and Ameren Illinois have the right to offset the borrowings against the cash surrender value of the policies and, consequently, present the net asset in “Other assets” on their respective balance sheets.

Disclosure of Compensation Related Costs, Share-based Payments

Performance Share Units

A performance share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, certain specified market conditions have been met and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date. In the event of a participant’s death or retirement at age 55 or older with five or more years of service, awards vest on a pro rata basis over the three-year performance period. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals.

The fair value of each performance share unit granted in 2018 was determined to be $62.88, which was based on Ameren’s closing common share price of $58.99 at December 31, 2017, 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, 2018, 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 1.98% and volatility of 15% to 23% for the peer group.

Restricted Stock Units

Restricted stock units vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if the individual remains employed with Ameren through the payment date of the awards. Generally, in the event of a participant’s death or retirement at age 55 or older with five or more years of service, awards vest on a pro rata basis. The payout date of the awards is approximately 38 months after the grant date. The fair value of each restricted stock unit is determined by Ameren’s closing common

Revenue Recognition

In the first quarter of 2018, we adopted authoritative accounting guidance related to revenue from contracts with customers using the full retrospective method, with no material changes to the amount or timing of revenue recognition. We record revenues from contracts with customers for various electric and natural gas services, which primarily consist of retail distribution, electric transmission, and off-system arrangements. When more than one performance obligation exists in a contract, the consideration under the contract is allocated to the performance obligations based on the relative standalone selling price.

Electric and natural gas retail distribution revenues are earned when the commodity is delivered to our customers. We accrue an estimate of electric and natural gas retail distribution revenues for service provided but unbilled at the end of each accounting period.

Electric transmission revenues are earned as electric transmission services are provided.

Off-system revenues are primarily comprised of MISO revenues and wholesale bilateral revenues. MISO revenues include the sale of electricity, capacity, and ancillary services. Wholesale bilateral revenues include the sale of electricity and capacity. MISO-related electricity and wholesale bilateral electricity revenues are earned as electricity is delivered. MISO-related capacity and ancillary service revenues and wholesale bilateral capacity revenues are earned as services are provided.

Retail distribution, electric transmission, and off-system revenues, including the underlying components described above, represent a series of goods or services that are substantially the same and have the same pattern of transfer over time to our customers. Revenues from contracts with customers is equal to the amounts billed and our estimate of electric and natural gas retail distribution services provided but unbilled at the end of each accounting period. Revenues are billed at least monthly, and payments are due less than one month after goods and/or services are provided. See Note 12 – Segment Information for disaggregated revenue information.

For certain regulatory recovery mechanisms that are alternative revenue programs, rather than revenues from contracts with customers, we 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 from the end of the year. Our alternative revenue programs include revenue requirement reconciliations, MEEIA, and VBA. These revenues are subsequently recognized as revenues from contracts with customers when billed, with an offset to alternative revenue program revenues.

The Ameren Companies elected to exclude disclosure related to the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied as of the end of the reporting period for contracts with an initial expected term of one year or less. As of June 30, 2018 and 2017, our remaining performance obligations were immaterial.

Excise Taxes

Ameren Missouri and Ameren Illinois collect from their customers excise taxes, including municipal and state excise taxes and gross receipts taxes, that are levied on the sale or distribution of natural gas and electricity. Excise taxes are recorded gross in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” on the statements of income.

Accounting and Reporting Developments

Accounting and Reporting Developments

In the first quarter of 2018, the Ameren Companies adopted authoritative accounting guidance on various topics. See the Operating Revenues section above for more information on our adoption of the guidance on revenue from contracts with customers. See Note 11 – Retirement Benefits for more information on our adoption of the guidance on the presentation of net periodic pension and postretirement benefit cost. See the Cash, Cash Equivalents, and Restricted Cash section above for more information on our adoption of the guidance on restricted cash. Our adoption of the guidance on the recognition and measurement of financial assets and financial liabilities did not have a material impact on our results of operations or financial position.

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, the measurement of credit losses on financial instruments, and the reclassification of certain tax effects from accumulated OCI.

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Financial Instruments Financial Instruments (Policies)

6 Months Ended

Jun. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

We use derivatives to manage the risk of changes in market prices for natural gas and power, 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 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

6 Months Ended

Jun. 30, 2018

Jun. 30, 2018

Accounting Policies [Abstract]

Schedule of Cash and Cash Equivalents Including Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets and the statements of cash flows as of June 30, 2018 and 2017, and December 31, 2017 and 2016:

	June 30, 2018						December 31, 2017						June 30, 2017						December 31, 2016
	Ameren		Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois
Cash and cash equivalents(a)	$	29	$	17	$	—	$	10	$	—	$	—	$	10	$	—	$	—	$	9	$	—	$	—
Restricted cash included in “Other current assets”	12		4		6		21		5		6		19		4		5		20		4		6
Restricted cash included in “Other assets”	51		—		51		35		—		35		23		—		23		22		—		22
Restricted cash included in “Nuclear decommissioning trust fund”	4		4		(b)		2		2		(b)		1		1		(b)		1		1		(b)
Total cash, cash equivalents, and restricted cash(c)	$	96	$	25	$	57	$	68	$	7	$	41	$	53	$	5	$	28	$	52	$	5	$	28

(a) As presented on the balance sheet.

(b) Not applicable.

(c) As presented on the statement of cash flows.

Schedule of Cash Flow, Supplemental Disclosures

The following table provides noncash investing activity excluded from the statements of cash flows for the six months ended June 30, 2018 and 2017:

	June 30, 2018						June 30, 2017
	Ameren(a)		Ameren Missouri		Ameren Illinois		Ameren(a)		Ameren Missouri		Ameren Illinois
Accrued capital expenditures	$	233	$	80	$	147	$	175	$	61	$	79
Net realized and unrealized gain – nuclear decommissioning trust fund	1		1		(b)		36		36		(b)

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

(b) Not applicable.

Asset Retirement Obligation Disclosure

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the six months ended June 30, 2018:

	Ameren Missouri				Ameren Illinois(a)		Ameren
Balance at December 31, 2017	$	640		(b)	$	4	$	644		(b)
Liabilities settled	(2		)		(c)		(2		)
Accretion(d)	14				(c)		14
Change in estimates(e)	(9		)		—		(9		)
Balance at June 30, 2018	$	643		(b)	$	4	$	647		(b)

(a) Included in “Other deferred credits and liabilities” on the balance sheet.

(b) Balance included $6 million in “Other current liabilities” on the balance sheet as of both December 31, 2017, and June 30, 2018, respectively.

(c) Less than $1 million.

(d) Accretion expense attributable to Ameren Missouri was recorded as a decrease to regulatory liabilities.

(e) Ameren Missouri changed its fair value estimate primarily due to a reduction in the cost estimate for closure of certain CCR storage facilities

Summary Of Nonvested Shares Related To Long-Term Incentive Plan

six months ended June 30, 2018:

	Performance Share Units				Restricted Stock Units
	Share Units		Weighted-average Fair Value per Share Unit		Stock Units		Weighted-average Fair Value per Stock Unit
Nonvested at January 1, 2018(a)	895,489		$	52.28	—		$	—
Granted	306,252		62.88		184,351		57.60
Forfeitures	(54,213	)	49.72		(3,560	)	58.99
Undistributed vested units(b)	(145,169	)	53.50		(12,983	)	58.98
Vested and distributed	(176,043	)	52.88		—		—
Nonvested at June 30, 2018(c)	826,316		$	56.03	167,808		$	57.46

(a) Does not include 712,572 undistributed vested performance share units.

(b) Undistributed vested units are awards that vested due to attainment of retirement eligibility by certain employees, but have not yet been distributed. For undistributed vested performance share units, the number of shares issued for retirement-eligible employees will vary depending on actual performance over the three-year performance period.

(c) Does not include 476,361 undistributed vested performance share units and 12,983 undistributed vested restricted stock units.

Schedule of Excise Taxes

The following table presents the excise taxes recorded in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” for the three and six months ended June 30, 2018 and 2017:

	Three Months					Six Months
	2018		2017			2018		2017
Ameren Missouri	$	46	$	40		$	80	$	71
Ameren Illinois	28		23		(a)	63		57		(a)
Ameren	$	74	$	63	(a)	$	143	$	128	(a)

(a) Amounts have been adjusted from those previously reported to reflect additional excise taxes for the three and six months ended June 30, 2017, respectively.

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The following table presents a reconciliation of the federal statutory corporate income tax rate to the effective income tax rate for the three and six months ended June 30, 2018 and 2017:

	Ameren		Ameren Missouri			Ameren Illinois
Three Months	2018	2017	2018		2017	2018	2017
Federal statutory corporate income tax rate:	21%	35%	21%		35%	21%	35%
Increases (decreases) from:
Amortization of excess deferred taxes	(1)	—	—	(a)	—	(5)	—
Other depreciation differences	—	—	—		—	(1)	(1)
Amortization of deferred investment tax credit	—	—	(1)		(1)	—	—
State tax	5	4	4		3	8	5
Tax credits	(1)	—	—		—	—	—
Other permanent items	—	(1)	—		—	—	—
Effective income tax rate	24%	38%	24%		37%	23%	39%
Six Months
Federal statutory corporate income tax rate:	21%	35%	21%		35%	21%	35%
Increases (decreases) from:
Amortization of excess deferred taxes	(2)	—	—	(a)	—	(4)	—
Amortization of deferred investment tax credit	(1)	(1)	(1)		(1)	—	—
State tax	6	5	4		3	7	5
Other permanent items	(1)	(2)	—		—	—	(1)
Effective income tax rate	23%	37%	24%		37%	24%	39%

(a) Based on an order issued by the MoPSC in July 2018, Ameren Missouri began amortizing excess deferred taxes in August 2018. See Note 2 – Rate and Regulatory Matters for additional information.

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

6 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

Schedule of Short-term Debt

The following table presents commercial paper outstanding, net of issuance discounts, as of June 30, 2018, and December 31, 2017:

	2018		2017
Ameren (parent)	$	506	$	383
Ameren Missouri	—		39
Ameren Illinois	—		62
Ameren Consolidated	$	506	$	484

The following table summarizes the borrowing activity and relevant interest rates under Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs for the six months ended June 30, 2018 and 2017:

	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated
2018
Average daily commercial paper outstanding at par value	$	397		$	123		$	174		$	693
Weighted-average interest rate	2.14		%	1.94		%	2.20		%	2.12		%
Peak commercial paper during period at par value(a)	$	506		$	481		$	442		$	1,295
Peak interest rate	2.45		%	2.42		%	2.55		%	2.55		%
2017
Average daily commercial paper outstanding at par value	$	736		$	6		$	66		$	808
Weighted-average interest rate	1.19		%	1.10		%	1.14		%	1.19		%
Peak commercial paper during period at par value(a)	$	841		$	60		$	163		$	948
Peak interest rate	1.50		%	1.41		%	1.50		%	1.50		%

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

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Other Income and Expenses (Tables)

6 Months Ended

Jun. 30, 2018

Other Nonoperating Income (Expense) [Abstract]

Other Income And Expenses

The following table presents the components of “Other Income, Net” in the Ameren Companies’ statements of income for the three and six months ended June 30, 2018 and 2017:

	Three Months							Six Months
	2018				2017			2018				2017
Ameren:(a)
Other Income, Net
Allowance for equity funds used during construction	$	9			$	4		$	14			$	10
Interest income on industrial development revenue bonds	7				6			13				13
Other interest income	2				3			4				5
Non-service cost components of net periodic benefit income	19			(b)	10			35			(b)	22
Other income	2				2			3				2
Donations	(6		)		(2		)	(11		)		(7		)
Other expense	(4		)		(3		)	(6		)		(7		)
Total Other Income, Net	$	29			$	20		$	52			$	38
Ameren Missouri:
Other Income, Net
Allowance for equity funds used during construction	$	7			$	4		$	11			$	9
Interest income on industrial development revenue bonds	7				6			13				13
Other interest income	1				1			1				1
Non-service cost components of net periodic benefit income	4			(b)	6			9			(b)	12
Other income	—				1			1				1
Donations	(2		)		(2		)	(3		)		(2		)
Other expense	(1		)		—			(3		)		(2		)
Total Other Income, Net	$	16			$	16		$	29			$	32
Ameren Illinois:
Other Income, Net
Allowance for equity funds used during construction	$	2			$	—		$	3			$	1
Interest income	1				2			3				4
Non-service cost components of net periodic benefit income	10				1			17				4
Other income	2				2			2				2
Donations	(1		)		(1		)	(5		)		(5		)
Other expense	(1		)		(1		)	(1		)		(3		)
Total Other Income, Net	$	13			$	3		$	19			$	3

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

(b) For the three and six months ended June 30, 2018, the non-service cost components of net periodic benefit income were partially offset by a $4 million and $8 million deferral due to a regulatory tracking mechanism for the difference between the level of such costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates.

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Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2018

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 June 30, 2018, and December 31, 2017. As of June 30, 2018, these contracts extended through October 2021, March 2023, and May 2032 for fuel oils, natural gas, and power, respectively.

	Quantity (in millions, except as indicated)
	2018			2017
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)(a)	40	(b)	40	28	(b)	28
Natural gas (in mmbtu)	23	149	172	24	139	163
Power (in megawatthours)	2	8	10	3	9	12

(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 June 30, 2018, and December 31, 2017:

	Balance Sheet Location	Ameren Missouri		Ameren Illinois		Ameren
2018
Fuel oils	Other current assets	$	8	$	—	$	8
	Other assets	5		—		5
Natural gas	Other current assets	—		1		1
	Other assets	—		1		1
Power	Other current assets	7		—		7
	Total assets (a)	$	20	$	2	$	22
Fuel oils	Other deferred credits and liabilities	$	1	$	—	$	1
Natural gas	Other current liabilities	4		12		16
	Other deferred credits and liabilities	3		13		16
Power	Other current liabilities	2		13		15
	Other deferred credits and liabilities	—		177		177
	Total liabilities (b)	$	10	$	215	$	225
2017
Fuel oils	Other current assets	$	5	$	—	$	5
	Other assets	2		—		2
Natural gas	Other assets	1		—		1
Power	Other current assets	9		—		9
	Total assets (a)	$	17	$	—	$	17
Natural gas	Other current liabilities	$	5	$	12	$	17
	Other deferred credits and liabilities	3		10		13
Power	Other current liabilities	1		13		14
	Other deferred credits and liabilities	—		182		182
	Total liabilities (b)	$	9	$	217	$	226

(a) The cumulative amount of pretax net gains on all derivative instruments is deferred as a regulatory liability.

(b) 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 June 30, 2018, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that counterparties could require. The additional collateral required is the net liability position allowed under the master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered on June 30, 2018, 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)
Ameren Missouri	$	63	$	4	$	52
Ameren Illinois	52		—		47
Ameren	$	115	$	4	$	99

(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)

6 Months Ended

Jun. 30, 2018

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 measured at fair value on a recurring basis and classified as Level 3 in the fair value hierarchy for the periods ended June 30, 2018, and December 31, 2017:

		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range
Level 3 Derivative asset and liability – commodity contracts(a):
2018
	Fuel oils	$	5	$	(1	)	Option model	Volatilities(%)(b)	20 – 34	25
							Discounted cash flow	Counterparty credit risk(%)(c)(d)	0.12 – 0.85	0.38
								Ameren Missouri credit risk(%)(c)(d)	0.35	(e)
	Natural gas	1		(5		)	Discounted cash flow	Nodal basis ($/mmbtu)(b)	(1.30) – 0.30	(0.90)
								Counterparty credit risk (%)(c)(d)	0.23 – 1	0.81
								Ameren Illinois credit risk (%)(c)(d)	0.35	(e)
	Power(f)	7		(192		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)(g)	24 – 39	27
								Estimated auction price for FTRs ($/MW)(b)	(898) – 1,180	57
								Nodal basis ($/MWh)(g)	(10) – 0	(2)
								Counterparty credit risk (%)(c)(d)	0.91	(e)
								Ameren Illinois credit risk (%)(c)(d)	0.35	(e)
							Fundamental energy production model	Estimated future natural gas prices ($/mmbtu)(b)	3	(e)
								Escalation rate (%)(b)(h)	4	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(b)	5 – 7	6
2017
	Fuel oils	$	3	$	—		Option model	Volatilities (%)(b)	20 – 26	22
							Discounted cash flow	Counterparty credit risk (%)(c)(d)	0.12 – 0.72	0.41
								Ameren Missouri credit risk (%)(c)(d)	0.37	(e)
	Natural gas	1		(4		)	Option model	Volatilities (%)(b)	26 – 46	37
								Nodal basis ($/mmbtu)(c)	(0.50) – (0.30)	(0.40)
							Discounted cash flow	Nodal basis ($/mmbtu)(b)	(1.20) – 0.10	(1)
								Counterparty credit risk (%)(c)(d)	0.37 – 0.92	0.53
								Ameren credit risk (%)(c)(d)	0.37	(e)
	Power(f)	8		(196		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)(g)	24 – 46	28
								Estimated auction price for FTRs ($/MW)(b)	(65) – 1,823	251
								Nodal basis ($/MWh)(g)	(10) – 0	(2)
								Counterparty credit risk (%)(c)(d)	0.28	(e)
								Ameren Illinois credit risk (%)(c)(d)	0.37	(e)
							Fundamental energy production model	Estimated future natural gas prices ($/mmbtu)(b)	3 – 4	3
								Escalation rate (%)(b)(h)	5	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)(b)	5 – 7	6

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

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

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

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

(e) Not applicable.

(f) Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2022 for June 30, 2018, and through 2021 for December 31, 2017. Valuations beyond 2022 for June 30, 2018, and 2021 for December 31, 2017, use fundamentally modeled pricing by month for peak and off-peak demand.

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

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

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 June 30, 2018:

		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	$	8	$	—	$	5	$	13
	Natural gas	—		1		1		2
	Power	—		—		7		7
	Total derivative assets – commodity contracts	$	8	$	1	$	13	$	22
	Nuclear decommissioning trust fund:
	Equity securities:
	U.S. large capitalization	$	481	$	—	$	—	$	481
	Debt securities:
	U.S. Treasury and agency securities	—		118		—		118
	Corporate bonds	—		78		—		78
	Other	—		31		—		31
	Total nuclear decommissioning trust fund	$	481	$	227	$	—	$	708	(b)
	Total Ameren	$	489	$	228	$	13	$	730
Ameren Missouri	Derivative assets – commodity contracts(a):
	Fuel oils	$	8	$	—	$	5	$	13
	Power	—		—		7		7
	Total derivative assets – commodity contracts	$	8	$	—	$	12	$	20
	Nuclear decommissioning trust fund:
	Equity securities:
	U.S. large capitalization	$	481	$	—	$	—	$	481
	Debt securities:
	U.S. Treasury and agency securities	—		118		—		118
	Corporate bonds	—		78		—		78
	Other	—		31		—		31
	Total nuclear decommissioning trust fund	$	481	$	227	$	—	$	708	(b)
	Total Ameren Missouri	$	489	$	227	$	12	$	728
Ameren Illinois	Derivative assets – commodity contracts(a):
	Natural gas	$	—	$	1	$	1	$	2
Liabilities:
Ameren	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	—	$	—	$	1	$	1
	Natural gas	1		26		5		32
	Power	—		—		192		192
	Total Ameren	$	1	$	26	$	198	$	225
Ameren Missouri	Derivative liabilities – commodity contracts(a):
	Fuel oils	$	—	$	—	$	1	$	1
	Natural gas			7		—		7
	Power	—		—		2		2
	Total Ameren Missouri	$	—	$	7	$	3	$	10
Ameren Illinois	Derivative liabilities – commodity contracts(a):
	Natural gas	$	1	$	19	$	5	$	25
	Power	—		—		190		190
	Total Ameren Illinois	$	1	$	19	$	195	$	215

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

(b) Balance excludes $6 million of cash and cash equivalents, 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, 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	$	4	$	—	$	3	$	7
	Natural gas	—		—		1		1
	Power	—		1		8		9
	Total derivative assets – commodity contracts	$	4	$	1	$	12	$	17
	Nuclear decommissioning trust fund:
	Equity securities:
	U.S. large capitalization	$	468	$	—	$	—	$	468
	Debt securities:
	U.S. Treasury and agency securities	—		125		—		125
	Corporate bonds	—		82		—		82
	Other	—		25		—		25
	Total nuclear decommissioning trust fund	$	468	$	232	$	—	$	700	(b)
	Total Ameren	$	472	$	233	$	12	$	717
Ameren Missouri	Derivative assets – commodity contracts(a):
	Fuel oils	$	4	$	—	$	3	$	7
	Natural gas	—		—		1		1
	Power	—		1		8		9
	Total derivative assets – commodity contracts	$	4	$	1	$	12	$	17
	Nuclear decommissioning trust fund:
	Equity securities:
	U.S. large capitalization	$	468	$	—	$	—	$	468
	Debt securities:
	U.S. Treasury and agency securities	—		125		—		125
	Corporate bonds	—		82		—		82
	Other	—		25		—		25
	Total nuclear decommissioning trust fund	$	468	$	232	$	—	$	700	(b)
	Total Ameren Missouri	$	472	$	233	$	12	$	717
Liabilities:
Ameren	Derivative liabilities – commodity contracts(a):
	Natural gas	$	1	$	25	$	4	$	30
	Power	—		—		196		196
	Total Ameren	$	1	$	25	$	200	$	226
Ameren Missouri	Derivative liabilities – commodity contracts(a):
	Natural gas	$	—	$	7	$	1	$	8
	Power	—		—		1		1
	Total Ameren Missouri	$	—	$	7	$	2	$	9
Ameren Illinois	Derivative liabilities – commodity contracts(a):
	Natural gas	$	1	$	18	$	3	$	22
	Power	—		—		195		195
	Total Ameren Illinois	$	1	$	18	$	198	$	217

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

(b) Balance excludes $4 million of cash and cash equivalents, 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 June 30, 2018
Beginning balance at April 1, 2018	$	4		$	(191	)	$	(187	)
Realized and unrealized losses included in regulatory assets/liabilities		(1	)		(2	)		(3	)
Purchases		4			—			4
Settlements		(2	)		3			1
Ending balance at June 30, 2018	$	5		$	(190	)	$	(185	)
Change in unrealized losses related to assets/liabilities held at June 30, 2018	$	—		$	(3	)	$	(3	)
For the three months ended June 30, 2017
Beginning balance at April 1, 2017	$	4		$	(194	)	$	(190	)
Realized and unrealized losses included in regulatory assets/liabilities		(1	)		(1	)		(2	)
Purchases		15			—			15
Settlements		(4	)		3			(1	)
Ending balance at June 30, 2017	$	14		$	(192	)	$	(178	)
Change in unrealized losses related to assets/liabilities held at June 30, 2017	$	—		$	(2	)	$	(2	)
For the six months ended June 30, 2018
Beginning balance at January 1, 2018	$	7		$	(195	)	$	(188	)
Realized and unrealized losses included in regulatory assets/liabilities		(3	)		(1	)		(4	)
Purchases		4			—			4
Settlements		(3	)		6			3
Ending balance at June 30, 2018	$	5		$	(190	)	$	(185	)
Change in unrealized losses related to assets/liabilities held at June 30, 2018	$	(1	)	$	(2	)	$	(3	)
For the six months ended June 30, 2017
Beginning balance at January 1, 2017	$	7		$	(185	)	$	(178	)
Realized and unrealized losses included in regulatory assets/liabilities		(1	)		(11	)		(12	)
Purchases		15			—			15
Settlements		(7	)		4			(3	)
Ending balance at June 30, 2017	$	14		$	(192	)	$	(178	)
Change in unrealized losses related to assets/liabilities held at June 30, 2017	$	—		$	(13	)	$	(13	)

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

The following table sets forth, by level within the fair value hierarchy, the carrying amount and fair value of financial assets and liabilities disclosed, but not carried, at fair value as of June 30, 2018, and December 31, 2017:

	June 30, 2018
	Carrying Amount			Fair Value
				Level 1		Level 2		Level 3			Total
Ameren:
Cash, cash equivalents, and restricted cash	$	96		$	96	$	—	$	—		$	96
Investments in held-to-maturity debt securities(a)	276			—		276		—			276
Short-term debt	506			—		506		—			506
Long-term debt (including current portion)(a)	8,460		(b)	—		8,411		438		(c)	8,849
Preferred stock(d)	142			—		140		—			140
Ameren Missouri:
Cash, cash equivalents, and restricted cash	$	25		$	25	$	—	$	—		$	25
Advances to money pool	66			—		66		—			66
Investments in held-to-maturity debt securities(a)	276			—		276		—			276
Long-term debt (including current portion)(a)	4,202		(b)	—		4,544		—			4,544
Preferred stock	80			—		79		—			79
Ameren Illinois:
Cash, cash equivalents, and restricted cash	$	57		$	57	$	—	$	—		$	57
Borrowings from money pool	31			—		31		—			31
Long-term debt (including current portion)	3,113		(b)	—		3,187		—			3,187
Preferred stock	62			—		61		—			61
	December 31, 2017
Ameren:
Cash, cash equivalents, and restricted cash	$	68		$	68	$	—	$	—		$	68
Investments in held-to-maturity debt securities(a)	276			—		276		—			276
Short-term debt	484			—		484		—			484
Long-term debt (including current portion)(a)	7,935		(b)	—		8,531		—			8,531
Preferred stock(c)	142			—		131		—			131
Ameren Missouri:
Cash, cash equivalents, and restricted cash	$	7		$	7	$	—	$	—		$	7
Investments in held-to-maturity debt securities(a)	276			—		276		—			276
Short-term debt	39			—		39		—			39
Long-term debt (including current portion)(a)	3,961		(b)	—		4,348		—			4,348
Preferred stock	80			—		80		—			80
Ameren Illinois:
Cash, cash equivalents, and restricted cash	$	41		$	41	$	—	$	—		$	41
Short-term debt	62			—		62		—			62
Long-term debt (including current portion)	2,830		(b)	—		3,028		—			3,028
Preferred stock	62			—		51		—			51

(a) Ameren and Ameren Missouri have investments in industrial revenue bonds, classified as held-to-maturity and recorded in “Other Assets,” that are equal to the capital lease obligation for CTs leased from the city of Bowling Green and Audrain County. As of June 30, 2018, and December 31, 2017, the carrying amount of both the investments in industrial revenue bonds and the capital lease obligations approximated fair value.

(b) Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $56 million, $23 million, and $27 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of June 30, 2018. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $50 million, $20 million, and $24 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2017.

(c) The Level 3 fair value amount consists of ATXI’s senior unsecured notes. In the first quarter of 2018, the amount was transferred to Level 3 because inputs to the valuation model became unobservable during the period.

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

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Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2018

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 and six months ended June 30, 2018 and 2017:

				Three Months				Six Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2018	$	3	$	(a)	$	6	$	(a)
agreements with Ameren Illinois		2017		6		(a)		17		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2018		6		1		11		2
rent and facility services		2017		6		1		13		2
Ameren Missouri and Ameren Illinois	Operating Revenues	2018		(b)		(b)		(b)		(b)
miscellaneous support services		2017		(b)		1		(b)		1
Total Operating Revenues		2018	$	9	$	1	$	17	$	2
		2017		12		2		30		3
Ameren Illinois power supply	Purchased Power	2018	$	(a)	$	3	$	(a)	$	6
agreements with Ameren Missouri		2017		(a)		6		(a)		17
Ameren Illinois transmission	Purchased Power	2018		(a)		1		(a)		1
services with ATXI		2017		(a)		1		(a)		1
Total Purchased Power		2018	$	(a)	$	4	$	(a)	$	7
		2017		(a)		7		(a)		18
Ameren Services support services	Other Operations and Maintenance	2018	$	32	$	30	$	65	$	60
agreement		2017		34		34		69		66
Money pool borrowings (advances)	Interest Charges/ Other Income, Net	2018	$	(b)	$	(b)	$	(b)	$	(b)
		2017		(b)		(b)		(b)		(b)

(a) Not applicable.

(b) Amount less than $1 million.

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Commitments And Contingencies Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase Commitment [Table Text Block]

The table below presents our estimated minimum fuel, purchased power, and other commitments for fuel at June 30, 2018. Ameren’s and Ameren Illinois’ purchased power commitments include the Ameren Illinois agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services, among other agreements, at June 30, 2018.

	Coal		Natural Gas(a)		Nuclear Fuel		Purchased Power(b)(c)		Methane Gas		Other		Total
Ameren:(d)
2018	$	181	$	148	$	51	$	130	$	2	$	56	$	568
2019	246		210		27		122		4		47		656
2020	85		125		38		30		4		62		344
2021	27		61		57		5		5		28		183
2022	—		12		12		—		5		26		55
Thereafter	—		39		62		—		58		93		252
Total	$	539	$	595	$	247	$	287	$	78	$	312	$	2,058
Ameren Missouri:
2018	$	181	$	22	$	51	$	—	$	2	$	39	$	295
2019	246		38		27		—		4		29		344
2020	85		30		38		—		4		44		201
2021	27		14		57		—		5		25		128
2022	—		5		12		—		5		26		48
Thereafter	—		17		62		—		58		74		211
Total	$	539	$	126	$	247	$	—	$	78	$	237	$	1,227
Ameren Illinois:
2018	$	—	$	126	$	—	$	130	$	—	$	5	$	261
2019	—		172		—		122		—		9		303
2020	—		95		—		30		—		9		134
2021	—		47		—		5		—		—		52
2022	—		7		—		—		—		—		7
Thereafter	—		22		—		—		—		—		22
Total	$	—	$	469	$	—	$	287	$	—	$	23	$	779

(a) Includes amounts for generation and for distribution.

(b) The purchased power amounts for Ameren and Ameren Illinois exclude agreements for renewable energy credits through 2032 with various renewable energy suppliers due to the contingent nature of the payment amounts.

(c) The purchased power amounts for Ameren and Ameren Missouri exclude a 102-megawatt power purchase agreement with a wind farm operator, which expires in 2024, due to the contingent nature of the payment amounts.

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

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Callaway Energy Center (Tables)

6 Months Ended

Jun. 30, 2018

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 as of June 30, 2018. 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 2018.

Type and Source of Coverage	Maximum Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	450		$	—
Pool participation	12,604		(a)	127		(b)
	$	13,054	(c)	$	127
Property damage:
NEIL and EMANI	$	3,200	(d)	$	27	(e)
Replacement power:
NEIL	$	490	(f)	$	7	(e)

(a) Provided through mandatory participation in an industrywide retrospective premium assessment program. The maximum coverage available is dependent on the number of United States commercial reactors participating in the 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 insurance for nonradiation events. EMANI provides $490 million in property damage insurance 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)

6 Months Ended

Jun. 30, 2018

Defined Benefit Plan [Abstract]

Components Of Net Periodic Benefit Cost

The following table presents the components of the net periodic benefit cost (income), prior to capitalization, incurred for Ameren’s pension and postretirement benefit plans for the three and six months ended June 30, 2018 and 2017:

	Pension Benefits												Postretirement Benefits
	Three Months						Six Months						Three Months						Six Months
	2018			2017			2018			2017			2018			2017			2018			2017
Service cost(a)	$	25		$	23		$	50		$	46		$	5		$	5		$	10		$	10
Non-service cost components:
Interest cost	42			45			84			90			9			11			20			23
Expected return on plan assets	(69		)	(65		)	(138		)	(131		)	(19		)	(18		)	(38		)	(37		)
Amortization of:
Prior service benefit	—			—			—			—			(1		)	(1		)	(2		)	(2		)
Actuarial loss (gain)	18			13			34			27			(3		)	(1		)	(3		)	(3		)
Total non-service cost components(b)	(9		)	(7		)	(20		)	(14		)	(14		)	(9		)	(23		)	(19		)
Net periodic benefit cost (income)	$	16		$	16		$	30		$	32		$	(9	)	$	(4	)	$	(13	)	$	(9	)

(a) Service cost, net of capitalization, is reflected in “Operating Expenses – Other operations and maintenance” on Ameren’s statement of income.

(b) 2018 amounts and the non-capitalized portion of 2017’s non-service cost components, as discussed above, are reflected in “Other Income, Net” on Ameren’s statement of income. See Note 5 – Other Income, Net for additional information.

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 respective share of net periodic pension and other postretirement benefit costs (income) incurred for the three and six months ended June 30, 2018 and 2017:

	Pension Benefits								Postretirement Benefits
	Three Months				Six Months				Three Months						Six Months
	2018		2017		2018		2017		2018			2017			2018			2017
Ameren Missouri(a)	$	6	$	6	$	11	$	12	$	—		$	(1	)	$	—		$	(2	)
Ameren Illinois	10		10		19		20		(9		)	(3		)	(13		)	(7		)
Ameren(a)	$	16	$	16	$	30	$	32	$	(9	)	$	(4	)	$	(13	)	$	(9	)

(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.

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Schedule Of Segment Reporting Information By Segment

The following tables present revenues, net income attributable to common shareholders, and capital expenditures by segment at Ameren and Ameren Illinois for the three and six months ended June 30, 2018 and 2017. 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
2018
External revenues	$	946	$	386	$	142	$	89		$	—		$	—		$	1,563
Intersegment revenues	9		1		—		14			—			(24		)	—
Net income attributable to Ameren common shareholders	168		33		7		36		(a)	(5		)	—			239
Capital expenditures	205		132		66		130			(2		)	2			533
2017
External revenues	$	922	$	387	$	134	$	92		$	2		$	—		$	1,537
Intersegment revenues	12		2		—		13			—			(27		)	—
Net income attributable to Ameren common shareholders	120		33		5		34		(a)	1			—			193
Capital expenditures	159		122		58		156			1			(2		)	494
Six Months
2018
External revenues	$	1,730	$	785	$	453	$	180		$	—		$	—		$	3,148
Intersegment revenues	17		2		—		27			—			(46		)	—
Net income attributable to Ameren common shareholders	206		66		49		73		(a)	(4		)	—			390
Capital expenditures	454		254		126		275			5			(2		)	1,112
2017
External revenues	$	1,695	$	771	$	398	$	188		$	—		$	—		$	3,052
Intersegment revenues	30		3		—		19			—			(52		)	—
Net income attributable to Ameren common shareholders	125		63		38		68		(a)	1			—			295
Capital expenditures	355		242		109		290			5			(3		)	998

(a) Ameren Transmission earnings include an allocation of financing costs from Ameren (parent).

Ameren Illinois

Three Months	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Intersegment Eliminations			Total Ameren Illinois
2018
External revenues	$	387	$	142	$	49	$	—		$	578
Intersegment revenues	—		—		13		(13		)	—
Net income available to common shareholder	33		7		22		—			62
Capital expenditures	132		66		104		—			302
2017
External revenues	$	389	$	134	$	53	$	—		$	576
Intersegment revenues	—		—		12		(12		)	—
Net income available to common shareholder	33		5		19		—			57
Capital expenditures	122		58		77		—			257
Six Months
2018
External revenues	$	787	$	453	$	98	$	—		$	1,338
Intersegment revenues	—		—		26		(26		)	—
Net income available to common shareholder	66		49		42		—			157
Capital expenditures	254		126		222		—			602
2017
External revenues	$	774	$	398	$	107	$	—		$	1,279
Intersegment revenues	—		—		18		(18		)	—
Net income available to common shareholder	63		38		35		—			136
Capital expenditures	242		109		133		—			484

Disaggregation of Revenue

The following tables present disaggregated revenues by segment at Ameren and Ameren Illinois for the three and six months ended June 30, 2018 and 2017. Economic factors affect the nature, timing, amount, and uncertainty of revenues and cash flows in a similar manner across customer classes. Revenues from alternative revenue programs have a similar distribution among customer classes as revenues from contracts with customers. Other revenues not associated with contracts with customers are presented in the Other customer classification, along with electric transmission and off-system revenues.

Ameren

Three Months	Ameren Missouri				Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission		Other		Intersegment Eliminations			Consolidated
2018
Residential	$	432			$	221	$	—	$	—	$	—	$	—		$	653
Commercial	364				126		—		—		—		—			490
Industrial	87				33		—		—		—		—			120
Other	47			(a)	7		—		103		—		(24		)	133		(a)
Total electric revenues	$	930			$	387	$	—	$	103	$	—	$	(24	)	$	1,396
Residential	$	13			$	—	$	97	$	—	$	—	$	—		$	110
Commercial	6				—		26		—		—		—			32
Industrial	—				—		5		—		—		—			5
Other	6				—		14		—		—		—			20
Total gas revenues	25				—		142		—		—		—			167
Total revenues(b)	$	955			$	387	$	142	$	103	$	—	$	(24	)	$	1,563
2017
Residential	$	358			$	208	$	—	$	—	$	—	$	—		$	566
Commercial	332				129		—		—		—		—			461
Industrial	84				28		—		—		—		—			112
Other	138				24		—		105		2		(26		)	243
Total electric revenues	$	912			$	389	$	—	$	105	$	2	$	(26	)	$	1,382
Residential	$	10			$	—	$	84	$	—	$	—	$	—		$	94
Commercial	4				—		24		—		—		—			28
Industrial	1				—		2		—		—		—			3
Other	7				—		24		—		—		(1		)	30
Total gas revenues	$	22			$	—	$	134	$	—	$	—	$	(1	)	$	155
Total revenues(b)	$	934			$	389	$	134	$	105	$	2	$	(27	)	$	1,537
Six Months
2018
Residential	$	764			$	440	$	—	$	—	$	—	$	—		$	1,204
Commercial	616				250		—		—		—		—			866
Industrial	148				68		—		—		—		—			216
Other	143			(a)	29		—		207		—		(46		)	333		(a)
Total electric revenues	$	1,671			$	787	$	—	$	207	$	—	$	(46	)	$	2,619
Residential	$	54			$	—	$	340	$	—	$	—	$	—		$	394
Commercial	22				—		93		—		—		—			115
Industrial	2				—		11		—		—		—			13
Other	(2		)		—		9		—		—		—			7
Total gas revenues	$	76			$	—	$	453	$	—	$	—	$	—		$	529
Total revenues(b)	$	1,747			$	787	$	453	$	207	$	—	$	(46	)	$	3,148
2017
Residential	$	644			$	427	$	—	$	—	$	—	$	—		$	1,071
Commercial	562				262		—		—		—		—			824
Industrial	142				56		—		—		—		—			198
Other	311				29		—		207		—		(51		)	496
Total electric revenues	$	1,659			$	774	$	—	$	207	$	—	$	(51	)	$	2,589
Residential	$	40			$	—	$	287	$	—	$	—	$	—		$	327
Commercial	16				—		79		—		—		—			95
Industrial	2				—		5		—		—		—			7
Other	8				—		27		—		—		(1		)	34
Total gas revenues	$	66			$	—	$	398	$	—	$	—	$	(1	)	$	463
Total revenues(b)	$	1,725			$	774	$	398	$	207	$	—	$	(52	)	$	3,052

(a) Includes $37 million and $47 million for the three and six months ended June 30, 2018, respectively, for the reduction to revenue for the excess amounts collected in rates related to the TCJA from January 1, 2018, through June 30, 2018. See Note 2 – Rate and Regulatory Matters for additional information.

(b) The following table presents revenues from alternative revenue programs and other revenues not from contracts with customers for the three and six months ended June 30, 2018 and 2017:

Three Months	Ameren Missouri			Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas			Ameren Transmission			Consolidated
2018
Revenues from alternative revenue programs	$	(5	)	$	15	$	(5	)	$	(5	)	$	—
Other revenues not from contracts with customers	5			3		—			—			8
2017
Revenues from alternative revenue programs	$	(7	)	$	16	$	1		$	2		$	12
Other revenues not from contracts with customers	3			1		1			—			5
Six Months
2018
Revenues from alternative revenue programs	$	(9	)	$	46	$	(8	)	$	(9	)	$	20
Other revenues not from contracts with customers	19			13		1			—			33
2017
Revenues from alternative revenue programs	$	(14	)	$	49	$	12		$	7		$	54
Other revenues not from contracts with customers	7			3		2			—			12

Ameren Illinois

Three Months	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Intersegment Eliminations			Total Ameren Illinois
2018
Residential	$	221	$	97	$	—	$	—		$	318
Commercial	126		26		—		—			152
Industrial	33		5		—		—			38
Other	7		14		62		(13		)	70
Total revenues(a)	$	387	$	142	$	62	$	(13	)	$	578
2017
Residential	$	208	$	84	$	—	$	—		$	292
Commercial	129		24		—		—			153
Industrial	28		2		—		—			30
Other	24		24		65		(12		)	101
Total revenues(a)	$	389	$	134	$	65	$	(12	)	$	576
Six Months
2018
Residential	$	440	$	340	$	—	$	—		$	780
Commercial	250		93		—		—			343
Industrial	68		11		—		—			79
Other	29		9		124		(26		)	136
Total revenues(a)	$	787	$	453	$	124	$	(26	)	$	1,338
2017
Residential	$	427	$	287	$	—	$	—		$	714
Commercial	262		79		—		—			341
Industrial	56		5		—		—			61
Other	29		27		125		(18		)	163
Total revenues(a)	$	774	$	398	$	125	$	(18	)	$	1,279

(a) The following table presents revenues from alternative revenue programs and other revenues not from contracts with customers for the Ameren Illinois segments for the three and six months ended June 30, 2018 and 2017:

Three Months	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas			Ameren Illinois Transmission			Consolidated
2018
Revenues from alternative revenue programs	$	15	$	(5	)	$	(5	)	$	5
Other revenues not from contracts with customers	3		—			—			3
2017
Revenues from alternative revenue programs	$	16	$	1		$	2		$	19
Other revenues not from contracts with customers	1		1			—			2
Six Months
2018
Revenues from alternative revenue programs	$	46	$	(8	)	$	(9	)	$	29
Other revenues not from contracts with customers	13		1			—			14
2017
Revenues from alternative revenue programs	$	49	$	12		$	5		$	66
Other revenues not from contracts with customers	3		2			—			5

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Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Basis Of Presentation And Significant Accounting Policies [Line Items]
Payables for purchased receivables	$ 40		$ 40		$ 31
Deferred Compensation Liability, Classified, Noncurrent	85		85		86
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net	17		17		17
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	19		19
Cash Surrender Value of Life Insurance	249		249		265
Corporate owned life insurance, borrowings	$ 107		$ 107		120
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	2.0	0.8	1.8	1.1
Ameren Illinois Company
Basis Of Presentation And Significant Accounting Policies [Line Items]
Payables for purchased receivables	$ 40		$ 40		31
Cash Surrender Value of Life Insurance	117		117		129
Corporate owned life insurance, borrowings	111		$ 111		$ 120
State and Local Jurisdiction [Member]
Basis Of Presentation And Significant Accounting Policies [Line Items]
State Income Tax Statutory Rate			4.00%
Deferred Tax Liabilities, Net	33		$ 33
State and Local Jurisdiction [Member] | Union Electric Company
Basis Of Presentation And Significant Accounting Policies [Line Items]
State Income Tax Statutory Rate			4.00%
Deferred Tax Liabilities, Net	$ 33		$ 33
State and Local Jurisdiction [Member] | Maximum
Basis Of Presentation And Significant Accounting Policies [Line Items]
State Income Tax Statutory Rate			6.25%
State and Local Jurisdiction [Member] | Maximum | Union Electric Company
Basis Of Presentation And Significant Accounting Policies [Line Items]
State Income Tax Statutory Rate			6.25%

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Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Cash and Cash Equivalents) (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016
Schedule of Cash and Cash Equivalents Including Restricted Cash [Line Items]
Cash and cash equivalents	$ 29	$ 10	$ 10	$ 9
Restricted Cash and Cash Equivalents	12	21	19	20
Restricted Cash and Cash Equivalents, Noncurrent	51	35	23	22
Restricted Cash and Cash Equivalents, Nuclear Decommissioning Trust Fund	4	2	1	1
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	96	68	53	52
Union Electric Company
Schedule of Cash and Cash Equivalents Including Restricted Cash [Line Items]
Cash and cash equivalents	17	0	0	0
Restricted Cash and Cash Equivalents	4	5	4	4
Restricted Cash and Cash Equivalents, Noncurrent	0	0	0	0
Restricted Cash and Cash Equivalents, Nuclear Decommissioning Trust Fund	4	2	1	1
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	25	7	5	5
Ameren Illinois Company
Schedule of Cash and Cash Equivalents Including Restricted Cash [Line Items]
Cash and cash equivalents	0	0	0	0
Restricted Cash and Cash Equivalents	6	6	5	6
Restricted Cash and Cash Equivalents, Noncurrent	51	35	23	22
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 57	$ 41	$ 28	$ 28

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Summary Of Significant Accounting Policies Summary of Significant Account Policies (Supplemental Cash Flow Information) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017
Supplemental Cash Flow Information [Line Items]
Capital Expenditures Incurred but Not yet Paid	$ 233	$ 175
Net Realized and Unrealized Gain (Loss) on Trading Securities	1	36
Union Electric Company
Supplemental Cash Flow Information [Line Items]
Capital Expenditures Incurred but Not yet Paid	80	61
Net Realized and Unrealized Gain (Loss) on Trading Securities	1	$ 36
Ameren Illinois Company
Supplemental Cash Flow Information [Line Items]
Capital Expenditures Incurred but Not yet Paid	$ 147		$ 79

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Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Schedule of Asset Retirement Obligations) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation	$ 647	$ 644
Liabilities settled	(2)
Accretion	14
Change of estimates	(9)
Other current liabilities	298	326
Union Electric Company
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation	643	640
Liabilities settled	(2)
Accretion	14
Change of estimates	(9)
Other current liabilities	107	103
Ameren Illinois Company
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation	4	4
Liabilities settled	(1)
Accretion	1
Change of estimates	0
Other current liabilities	150	177
Asset Retirement Obligation Balance
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Other current liabilities	6	6
Asset Retirement Obligation Balance | Union Electric Company
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Other current liabilities	$ 6	$ 6

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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	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Dec. 31, 2017
Weighted-average Fair Value per Unit at Grant Date
Closing common share price (in dollars per share)			$ 58.99
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Fully Vested Undistributed to Retirement-eligible employees.	476,361	476,361	712,572
Share Units
Share Units, Nonvested as of beginning of year		895,489
Share Units, Granted		306,252
Share Units, Forfeitures		(54,213)
Share Units, Undistributed Vested		(145,169)
Share Units, Vested		(176,043)
Share Units, Nonvested as of Current period end	826,316	826,316
Weighted-average Fair Value per Unit at Grant Date
Weighted-average Fair Value per Unit, Nonvested as of Beginning of year		$ 52.28
Weighted-average Fair Value per Unit, Granted		62.88
Weighted-average Fair Value per Unit, Forfeitures		49.72
Weighted-average Fair Value per Unit, Undistributed Vested Units		53.50
Weighted-average Fair Value per Unit, Vested		52.88
Weighted-average Fair Value per Unit, Nonvested as of Current period end	$ 56.03	$ 56.03
Performance period		3 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		38 months
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period		5 years
Risk free interest rate period		3 years
Three-year risk-free rate		1.98%
Volatility rate, minimum		15.00%
Volatility rate, maximum		23.00%
Stock Issued During Period Percentage Conversion Of Units, Low End	0.00%
Stock Issued During Period Percentage Conversion Of Units, High End	200.00%
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Fully Vested Undistributed to Retirement-eligible employees.	12,983	12,983
Share Units
Share Units, Nonvested as of beginning of year		0
Share Units, Granted		184,351
Share Units, Forfeitures		(3,560)
Share Units, Undistributed Vested		(12,983)
Share Units, Vested		0
Share Units, Nonvested as of Current period end	167,808	167,808
Weighted-average Fair Value per Unit at Grant Date
Weighted-average Fair Value per Unit, Nonvested as of Beginning of year		$ 0.00
Weighted-average Fair Value per Unit, Granted		57.60
Weighted-average Fair Value per Unit, Forfeitures		58.99
Weighted-average Fair Value per Unit, Undistributed Vested Units		58.98
Weighted-average Fair Value per Unit, Vested		0.00
Weighted-average Fair Value per Unit, Nonvested as of Current period end	$ 57.46	$ 57.46
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		38 months
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period		5 years

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Summary Of Significant Accounting Policies (Schedule Of Excise Taxes) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Accounting Policies [Line Items]
Excise tax expense	$ 74	$ 63	$ 143	$ 128
Union Electric Company
Accounting Policies [Line Items]
Excise tax expense	46	40	80	71
Ameren Illinois Company
Accounting Policies [Line Items]
Excise tax expense	$ 28	$ 23	$ 63	$ 57

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Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Income Taxes) (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2018 Rate	Jun. 30, 2017 Rate	Jun. 30, 2018 Rate	Jun. 30, 2017 Rate
Basis Of Presentation And Significant Accounting Policies [Line Items]
Federal statutory corporate income tax rate:	21.00%	35.00%	21.00%	35.00%
Amortization of excess deferred taxes	(1.00%)	0.00%	(2.00%)	0.00%
Other depreciation differences	0.00%	0.00%
Amortization of deferred investment tax credit	(0.00%)	(0.00%)	(1.00%)	(1.00%)
State tax	5.00%	4.00%	6.00%	5.00%
Tax credits	(1.00%)	(0.00%)
Other permanent items	0.00%	(1.00%)	(1.00%)	(2.00%)
Effective income tax rate	24.00%	38.00%	23.00%	37.00%
Union Electric Company
Basis Of Presentation And Significant Accounting Policies [Line Items]
Federal statutory corporate income tax rate:	21.00%	35.00%	21.00%	35.00%
Amortization of excess deferred taxes	0.00%	0.00%	0.00%	0.00%
Other depreciation differences	0.00%	0.00%
Amortization of deferred investment tax credit	(1.00%)	(1.00%)	(1.00%)	(1.00%)
State tax	4.00%	3.00%	4.00%	3.00%
Tax credits	(0.00%)	(0.00%)
Other permanent items	0.00%	0.00%	0.00%	0.00%
Effective income tax rate	24.00%	37.00%	24.00%	37.00%
Ameren Illinois Company
Basis Of Presentation And Significant Accounting Policies [Line Items]
Federal statutory corporate income tax rate:	21.00%	35.00%	21.00%	35.00%
Amortization of excess deferred taxes	(5.00%)	0.00%	(4.00%)	0.00%
Other depreciation differences	(1.00%)	(1.00%)
Amortization of deferred investment tax credit	(0.00%)	(0.00%)	(0.00%)	(0.00%)
State tax	8.00%	5.00%	7.00%	5.00%
Tax credits	(0.00%)	(0.00%)
Other permanent items	0.00%	0.00%	0.00%	(1.00%)
Effective income tax rate	23.00%	39.00%	24.00%	39.00%

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Rate And Regulatory Matters (Narrative-Missouri) (Detail) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) MWh	Jun. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Rate And Regulatory Matters [Line Items]
Regulatory Liability, Noncurrent	$ 4,540		$ 4,540		$ 4,387
Total operating revenues	1,563	$ 1,537	3,148	$ 3,052
Union Electric Company
Rate And Regulatory Matters [Line Items]
Regulatory Liability, Noncurrent	$ 2,754		$ 2,754		$ 2,664
PISA Deferral Percentage			85.00%
Recovery period for plant in service accounting deferrals			20 years
MEEIAEnergyEfficiencyInvestments			$ 92
Electricity | Union Electric Company
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			167
Estimated incremental capital Investment			1,000
Incentive Award if Energy Efficiency Goals Are Achieved			$ 115
Achieved Percentage of Energy Efficiency Earnings For Incentive Award	100.00%		100.00%
TCJA - Excess Amounts Collected in Rates
Rate And Regulatory Matters [Line Items]
Regulatory Liability, Noncurrent	$ 47		$ 47
TCJA - Excess Accumulated Deferred Income Tax Amortization | Electricity | Union Electric Company
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 74
Wind Generation Facility | Union Electric Company
Rate And Regulatory Matters [Line Items]
Amount of Megawatts | MWh			400
Renewable Choice Program | Union Electric Company
Rate And Regulatory Matters [Line Items]
Amount of Megawatts | MWh			400
Renewable Choice Program | Electricity | Union Electric Company
Rate And Regulatory Matters [Line Items]
Percentage of Energy Received From Renewable Resources	100.00%
Renewable Choice Program - Megawatts Owned [Member] | Union Electric Company
Rate And Regulatory Matters [Line Items]
Amount of Megawatts | MWh			200
MEEIA 2016 | Final Rate Order | Union Electric Company
Rate And Regulatory Matters [Line Items]
Total operating revenues			$ 5
MEEIA 2016 | Final Rate Order | Electricity | Union Electric Company
Rate And Regulatory Matters [Line Items]
Incentive Award if Energy Efficiency Goals Are Achieved			$ 27
Achieved Percentage of Energy Efficiency Earnings For Incentive Award	100.00%		100.00%
MEEIA 2013 | Electricity | Union Electric Company
Rate And Regulatory Matters [Line Items]
Incentive Award if Energy Efficiency Goals Are Achieved			$ 9
Minimum | Electricity | Union Electric Company
Rate And Regulatory Matters [Line Items]
Annual Incentive Award if Energy Efficiency Goals Are Achieved			$ 10
Maximum
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage			2.85%
Maximum | Electricity | Union Electric Company
Rate And Regulatory Matters [Line Items]
Annual Incentive Award if Energy Efficiency Goals Are Achieved			$ 24

XML

Rate And Regulatory Matters (Narrative-Illinois) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended	9 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Jun. 30, 2018	Sep. 30, 2018	Dec. 31, 2017
Rate And Regulatory Matters [Line Items]
Regulatory assets		$ 1,205	$ 1,205		$ 1,230
Ameren Illinois Company
Rate And Regulatory Matters [Line Items]
Regulatory assets		822	822		$ 822
Ameren Illinois Company | Natural Gas
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			17
Ameren Illinois Company | Electric Distribution
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			50
2018 IEIMA Revenue Requirement Reconciliation | IEIMA | Ameren Illinois Company | Electric Distribution
Rate And Regulatory Matters [Line Items]
Regulatory assets		62	$ 62
Pending Rate Case | Ameren Illinois Company | Electric Distribution
Rate And Regulatory Matters [Line Items]
Electric Energy-Efficiency Revenue Requirement		34
Pending Rate Case | FEJA energy-efficiency rider [Domain] | Ameren Illinois Company | Electric Distribution
Rate And Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 20
Subsequent Event | Pending Rate Case | Ameren Illinois Company | Natural Gas
Rate And Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 37
Public Utilities, Requested Return on Equity, Percentage	9.87%
Public Utilities, Requested Equity Capital Structure, Percentage				50.00%
Rate Base				$ 1,600
Subsequent Event | Pending Rate Case | IEIMA | Ameren Illinois Company | Electric Distribution
Rate And Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 72
Subsequent Event | TCJA - Reduction in Federal Statutory Income Tax Rate | Ameren Illinois Company | Natural Gas
Rate And Regulatory Matters [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 17

XML

Rate And Regulatory Matters (Narrative-Federal) (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Rate And Regulatory Matters [Line Items]
Current regulatory liabilities	$ 133	$ 128
Ameren Illinois Company
Rate And Regulatory Matters [Line Items]
Current regulatory liabilities	$ 65	$ 92
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 | Ameren Illinois Company
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 27
Midwest Independent Transmission System Operator, Inc | Ameren Transmission Company of Illinois
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 23
Midwest Independent Transmission System Operator, Inc | Final Rate Order
Rate And Regulatory Matters [Line Items]
Public Utilities, Approved Return on Equity, Percentage	10.32%
Customer Requested Rate on Equity	9.15%
Incentive adder to FERC allowed base return on common equity	0.50%
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	$ 43
Midwest Independent Transmission System Operator, Inc | Pending Ferc Case | Ameren Illinois Company
Rate And Regulatory Matters [Line Items]
Current regulatory liabilities	$ 25
Maximum | Midwest Independent Transmission System Operator, Inc | Final Rate Order
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%

XML

Short-Term Debt And Liquidity (Narrative) (Detail)	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($)	Jun. 30, 2017	Jun. 30, 2018 USD ($)	Jun. 30, 2017
Credit Agreements
Short-term Debt [Line Items]
Actual debt-to-capital ratio	0.54		0.54
Line of credit facility, maximum borrowing capacity	$ 1,600,000,000.0		$ 1,600,000,000.0
Utilities [Member]
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate, over Time	2.17%	1.27%	2.04%	1.14%
Union Electric Company | Missouri Credit Agreement
Short-term Debt [Line Items]
Actual debt-to-capital ratio	0.48		0.48
Ameren Illinois Company | Illinois Credit Agreement
Short-term Debt [Line Items]
Actual debt-to-capital ratio	0.47		0.47

XML

Short-Term Debt And Liquidity Short-Term Debt and Liquidity (Commercial Paper outstanding) (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Commercial paper outstanding	$ 506	$ 484
Ameren (parent)
Short-term Debt [Line Items]
Commercial paper outstanding	506	383
Union Electric Company
Short-term Debt [Line Items]
Commercial paper outstanding	0	39
Ameren Illinois Company
Short-term Debt [Line Items]
Commercial paper outstanding	$ 0	$ 62

XML

Short-Term Debt And Liquidity Short-Term Debt and Liquidity (Commercial Paper) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Short-term Debt [Line Items]
Short-term Debt, Average Outstanding Amount	$ 693	$ 808
Weighted-average interest rate	2.12%	1.19%
Short-term Debt, Maximum Amount Outstanding During Period	$ 1,295	$ 948
Peak interest rate	2.55%	1.50%
Ameren (parent)
Short-term Debt [Line Items]
Short-term Debt, Average Outstanding Amount	$ 397	$ 736
Weighted-average interest rate	2.14%	1.19%
Short-term Debt, Maximum Amount Outstanding During Period	$ 506	$ 841
Peak interest rate	2.45%	1.50%
Union Electric Company
Short-term Debt [Line Items]
Short-term Debt, Average Outstanding Amount	$ 123	$ 6
Weighted-average interest rate	1.94%	1.10%
Short-term Debt, Maximum Amount Outstanding During Period	$ 481	$ 60
Peak interest rate	2.42%	1.41%
Ameren Illinois Company
Short-term Debt [Line Items]
Short-term Debt, Average Outstanding Amount	$ 174	$ 66
Weighted-average interest rate	2.20%	1.14%
Short-term Debt, Maximum Amount Outstanding During Period	$ 442	$ 163
Peak interest rate	2.55%	1.50%

XML

Long-Term debt and Equity Financings (Narrative) (Details) - USD ($) shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2018	Jun. 30, 2017
Long-Term Debt And Equity Financings [Line Items]
Stock Issued During Period, Shares, New Issues	0.4	0.7	0.7
Noncash financing activity - Issuance of common stock for stock-based compensation		$ 35,000,000	$ 35,000,000	$ 0
Issuance of common stock	$ 23,000,000		40,000,000	$ 0
Union Electric Company | First Mortgage Bonds, 4.00%, Due 2048 - $425 Issuance [Member] | Secured Debt
Long-Term Debt And Equity Financings [Line Items]
Total principal amount of notes	$ 425,000,000		$ 425,000,000
State interest rate	4.00%		4.00%
Proceeds from Issuance of Secured Debt			$ 419,000,000
Union Electric Company | Senior Secured Notes 6 Point 00 Due 2018 [Member] | Secured Debt
Long-Term Debt And Equity Financings [Line Items]
State interest rate	6.00%		6.00%
Repayments of other long-term debt			$ 179,000,000
Ameren Illinois Company | First Mortgage Bonds, 3.80%, Due 2028 [Member] | Secured Debt
Long-Term Debt And Equity Financings [Line Items]
Total principal amount of notes	$ 430,000,000		$ 430,000,000
State interest rate	3.80%		3.80%
Proceeds from Issuance of Secured Debt	$ 427,000,000
Ameren Illinois Company | Senior Secured Notes6250 Due2018 [Member] | Secured Debt
Long-Term Debt And Equity Financings [Line Items]
State interest rate	6.25%		6.25%
Repayments of other long-term debt			$ 144,000,000

XML

Other Income, Net (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Other Nonoperating Income (Expense) [Line Items]
Allowance for equity funds used during construction	$ 9	$ 4	$ 14	$ 10
Interest income on industrial development revenue bonds	7	6	13	13
Interest income	2	3	4	5
Non-service cost components of net periodic benefit income	19	10	35	22
Other income	2	2	3	2
Donations	(6)	(2)	(11)	(7)
Other expense	(4)	(3)	(6)	(7)
Other Income (Expense), Net	29	20	52	38
Union Electric Company
Other Nonoperating Income (Expense) [Line Items]
Allowance for equity funds used during construction	7	4	11	9
Interest income on industrial development revenue bonds	7	6	13	13
Interest income	1	1	1	1
Non-service cost components of net periodic benefit income	4	6	9	12
Other income	0	1	1	1
Donations	(2)	(2)	(3)	2
Other expense	(1)	0	(3)	(2)
Other Income (Expense), Net	16	16	29	32
Defined Benefit Plan, Non-service Cost or Income Components - Tracker	4		8
Ameren Illinois Company
Other Nonoperating Income (Expense) [Line Items]
Allowance for equity funds used during construction	2	0	3	1
Interest income	1	2	3	4
Non-service cost components of net periodic benefit income	10	1	17	4
Other income	2	2	2	2
Donations	(1)	(1)	(5)	(5)
Other expense	(1)	(1)	(1)	(3)
Other Income (Expense), Net	$ 13	$ 3	$ 19	$ 3

XML

Financial Instruments (Open Gross Derivative Volumes By Commodity Type) (Detail) gal in Millions, MWh in Millions, MMBTU in Millions	Jun. 30, 2018 MWh gal MMBTU	Dec. 31, 2017 MWh gal MMBTU
Fuel Oils
Derivative [Line Items]
Quantity | gal	40	28
Natural Gas
Derivative [Line Items]
Quantity | MMBTU	172	163
Power
Derivative [Line Items]
Quantity | MWh	10	12
Union Electric Company | Fuel Oils
Derivative [Line Items]
Quantity | gal	40	28
Union Electric Company | Natural Gas
Derivative [Line Items]
Quantity | MMBTU	23	24
Union Electric Company | Power
Derivative [Line Items]
Quantity | MWh	2	3
Ameren Illinois Company | Natural Gas
Derivative [Line Items]
Quantity | MMBTU	149	139
Ameren Illinois Company | Power
Derivative [Line Items]
Quantity | MWh	8	9

XML

Financial Instruments (Derivative Instruments Carrying Value) (Detail) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative assets	$ 1
Derivative liabilities	225
Not Designated As Hedging Instrument
Derivative [Line Items]
Derivative assets	22	$ 17
Derivative liabilities		226
Not Designated As Hedging Instrument | Fuel Oils | Other Current Assets
Derivative [Line Items]
Derivative assets	8	5
Not Designated As Hedging Instrument | Fuel Oils | Other Assets
Derivative [Line Items]
Derivative assets	5	2
Not Designated As Hedging Instrument | Fuel Oils | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities	1
Not Designated As Hedging Instrument | Natural Gas | Other Current Assets
Derivative [Line Items]
Derivative assets	1
Not Designated As Hedging Instrument | Natural Gas | Other Assets
Derivative [Line Items]
Derivative assets	1	1
Not Designated As Hedging Instrument | Natural Gas | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities	16	17
Not Designated As Hedging Instrument | Natural Gas | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities	16	13
Not Designated As Hedging Instrument | Power | Other Current Assets
Derivative [Line Items]
Derivative assets	7	9
Not Designated As Hedging Instrument | Power | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities	15	14
Not Designated As Hedging Instrument | Power | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities	177	182
Union Electric Company | Not Designated As Hedging Instrument
Derivative [Line Items]
Derivative assets	20	17
Derivative liabilities	10	9
Union Electric Company | Not Designated As Hedging Instrument | Fuel Oils | Other Current Assets
Derivative [Line Items]
Derivative assets	8	5
Union Electric Company | Not Designated As Hedging Instrument | Fuel Oils | Other Assets
Derivative [Line Items]
Derivative assets	5	2
Union Electric Company | Not Designated As Hedging Instrument | Fuel Oils | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities	1
Union Electric Company | Not Designated As Hedging Instrument | Natural Gas | Other Current Assets
Derivative [Line Items]
Derivative assets	0
Union Electric Company | Not Designated As Hedging Instrument | Natural Gas | Other Assets
Derivative [Line Items]
Derivative assets	0	1
Union Electric Company | Not Designated As Hedging Instrument | Natural Gas | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities	4	5
Union Electric Company | Not Designated As Hedging Instrument | Natural Gas | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities	3	3
Union Electric Company | Not Designated As Hedging Instrument | Power | Other Current Assets
Derivative [Line Items]
Derivative assets	7	9
Union Electric Company | Not Designated As Hedging Instrument | Power | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities	2	1
Union Electric Company | Not Designated As Hedging Instrument | Power | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities	0	0
Ameren Illinois Company | Not Designated As Hedging Instrument
Derivative [Line Items]
Derivative assets	2	0
Derivative liabilities	215	217
Ameren Illinois Company | Not Designated As Hedging Instrument | Fuel Oils | Other Current Assets
Derivative [Line Items]
Derivative assets	0	0
Ameren Illinois Company | Not Designated As Hedging Instrument | Fuel Oils | Other Assets
Derivative [Line Items]
Derivative assets	0	0
Ameren Illinois Company | Not Designated As Hedging Instrument | Fuel Oils | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities	0
Ameren Illinois Company | Not Designated As Hedging Instrument | Natural Gas | Other Current Assets
Derivative [Line Items]
Derivative assets	1
Ameren Illinois Company | Not Designated As Hedging Instrument | Natural Gas | Other Assets
Derivative [Line Items]
Derivative assets	1	0
Ameren Illinois Company | Not Designated As Hedging Instrument | Natural Gas | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities	12	12
Ameren Illinois Company | Not Designated As Hedging Instrument | Natural Gas | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities	13	10
Ameren Illinois Company | Not Designated As Hedging Instrument | Power | Other Current Assets
Derivative [Line Items]
Derivative assets	0	0
Ameren Illinois Company | Not Designated As Hedging Instrument | Power | Other Current Liabilities
Derivative [Line Items]
Derivative liabilities	13	13
Ameren Illinois Company | Not Designated As Hedging Instrument | Power | Other Deferred Credits And Liabilities
Derivative [Line Items]
Derivative liabilities	$ 177	$ 182

XML

Financial Instruments (Derivative Instruments With Credit Risk-Related Contingent Features) (Detail) $ in Millions	Jun. 30, 2018 USD ($)
Derivative [Line Items]
Aggregate Fair Value of Derivative Liabilities	$ 115
Cash Collateral Posted	4
Potential Aggregate Amount of Additional Collateral Required	99
Union Electric Company
Derivative [Line Items]
Aggregate Fair Value of Derivative Liabilities	63
Cash Collateral Posted	4
Potential Aggregate Amount of Additional Collateral Required	52
Ameren Illinois Company
Derivative [Line Items]
Aggregate Fair Value of Derivative Liabilities	52
Cash Collateral Posted	0
Potential Aggregate Amount of Additional Collateral Required	$ 47

XML

Fair Value Measurements (Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis) (Detail) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	$ 1
Nuclear Decommissioning Trust Fund	708	$ 700
Assets fair value	730	717
Derivative liabilities	225
Excluded receivables, payables, and accrued income, net	6	4
Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	708	700
Assets fair value	728	717
Excluded receivables, payables, and accrued income, net	6	4
Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	22	17
Derivative liabilities	225	226
Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	20	17
Derivative liabilities	10	9
Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	215	217
Equity Securities | U.S. large capitalization
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	481	468
Equity Securities | U.S. large capitalization | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	481	468
Debt Securities | Corporate bonds
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	78	82
Debt Securities | Corporate bonds | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	78	82
Debt Securities | US treasury and government securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	118	125
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	125
Debt Securities | Other Debt Securities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	31	25
Debt Securities | Other Debt Securities | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	31	25
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	481	468
Assets fair value	489	472
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	481	468
Assets fair value	489	472
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	8	4
Derivative liabilities	1	1
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	8	4
Derivative liabilities	0	0
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	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	481	468
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	481	468
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	227	232
Assets fair value	228	233
Significant Other Observable Inputs (Level 2) | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	227	232
Assets fair value	227	233
Significant Other Observable Inputs (Level 2) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	1
Derivative liabilities	26	25
Significant Other Observable Inputs (Level 2) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	0	1
Derivative liabilities	7	7
Significant Other Observable Inputs (Level 2) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	19	18
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	78	82
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	78	82
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	125
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	125
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	31	25
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	31	25
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	13	12
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	12	12
Significant Other Unobservable Inputs (Level 3) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	13	12
Derivative liabilities	198	200
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	12	12
Derivative liabilities	3	2
Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	195	198
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
Fuel Oils | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	13	7
Derivative liabilities	1
Fuel Oils | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	13	7
Derivative liabilities	1
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	8	4
Derivative liabilities	0
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	8	4
Derivative liabilities	0
Fuel Oils | Significant Other Observable Inputs (Level 2) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	0	0
Derivative liabilities	0
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	0
Derivative liabilities	0
Fuel Oils | Significant Other Unobservable Inputs (Level 3) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	5	3
Derivative liabilities	1
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	5	3
Derivative liabilities	1
Power | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	7	9
Derivative liabilities	192	196
Power | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	7	9
Derivative liabilities	2	1
Power | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	190	195
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	0
Derivative liabilities	0	0
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	0
Derivative liabilities	0	0
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	0
Power | Significant Other Observable Inputs (Level 2) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	0	1
Derivative liabilities	0	0
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	1
Derivative liabilities	0	0
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	0
Power | Significant Other Unobservable Inputs (Level 3) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	7	8
Derivative liabilities	192	196
Power | Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	7	8
Derivative liabilities	2	1
Power | Significant Other Unobservable Inputs (Level 3) | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	190	195
Natural Gas | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	2	1
Derivative liabilities	32	30
Natural Gas | Commodity Contract | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		1
Derivative liabilities	7	8
Natural Gas | Commodity Contract | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	2
Derivative liabilities	25	22
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	0	0
Derivative liabilities	1	1
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		0
Derivative liabilities		0
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	0
Derivative liabilities	1	1
Natural Gas | Significant Other Observable Inputs (Level 2) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	0
Derivative liabilities	26	25
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		0
Derivative liabilities	7	7
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	1
Derivative liabilities	19	18
Natural Gas | Significant Other Unobservable Inputs (Level 3) | Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		1
Derivative liabilities	5	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		1
Derivative liabilities	0	1
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	1
Derivative liabilities	$ 5	$ 3

XML

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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	$ (185)	$ (178)	$ (185)	$ (178)	$ (187)	$ (188)	$ (190)	$ (178)
Included in regulatory assets/liabilities	(3)	(2)	(4)	(12)
Purchases	4	15	4	15
Settlements	1	(1)	3	(3)
Change in unrealized gains (losses) related to assets/liabilities held at period end	(3)	(2)	(3)	(13)
Union Electric Company
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	5	14	5	14	4	7	4	7
Included in regulatory assets/liabilities	(1)	(1)	(3)	(1)
Purchases	4	15	4	15
Settlements	(2)	(4)	(3)	(7)
Change in unrealized gains (losses) related to assets/liabilities held at period end	0	0	(1)	0
Ameren Illinois Company
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	(190)	(192)	(190)	(192)	$ (191)	$ (195)	$ (194)	$ (185)
Included in regulatory assets/liabilities	(2)	(1)	(1)	(11)
Purchases	0	0	0	0
Settlements	3	3	6	4
Change in unrealized gains (losses) related to assets/liabilities held at period end	$ (3)	$ (2)	$ (2)	$ (13)

XML

Fair Value Measurements (Schedule Of Valuation Process And Unobservable Inputs) (Detail) $ in Millions	Jun. 30, 2018 USD ($) $ / MW $ / MMBTU $ / MWh $ / credit	Dec. 31, 2017 USD ($)	Jun. 30, 2017 $ / MW $ / MMBTU $ / MWh $ / credit
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets | $	$ 1
Derivative liabilities | $	(225)
Natural Gas | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets | $	1	$ 1
Natural Gas | Derivative Liabilities
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities | $	5	(4)
Fuel Oils | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets | $	5	3
Fuel Oils | Derivative Liabilities
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities | $	(1)	0
Power | Derivative Assets
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets | $	7	8
Power | Derivative Liabilities
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities | $	$ 192	$ (196)
Measurement Input, Counterparty Credit Risk [Member] | Natural Gas | Discounted Cash Flow | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input			0.0037
Measurement Input, Counterparty Credit Risk [Member] | Natural Gas | Discounted Cash Flow | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input			0.0092
Measurement Input, Counterparty Credit Risk [Member] | Natural Gas | Discounted Cash Flow | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input			0.0053
Measurement Input, Counterparty Credit Risk [Member] | Fuel Oils | Discounted Cash Flow | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.0012		0.0012
Measurement Input, Counterparty Credit Risk [Member] | Fuel Oils | Discounted Cash Flow | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.0085		0.0072
Measurement Input, Counterparty Credit Risk [Member] | Fuel Oils | Discounted Cash Flow | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.0038		0.0041
Measurement Input, Counterparty Credit Risk [Member] | Power | Discounted Cash Flow | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.0091		0.0028
Measurement Input, Counterparty Credit Risk [Member] | Power | Discounted Cash Flow | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.0091		0.0028
Measurement Input, Counterparty Credit Risk [Member] | Power | Discounted Cash Flow | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.0091		0.0028
Measurement Input, Entity Credit Risk [Member] | Natural Gas | Discounted Cash Flow | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.35		0.0037
Measurement Input, Entity Credit Risk [Member] | Natural Gas | Discounted Cash Flow | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.35		0.0037
Measurement Input, Entity Credit Risk [Member] | Natural Gas | Discounted Cash Flow | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.35		0.0037
Measurement Input, Entity Credit Risk [Member] | Fuel Oils | Discounted Cash Flow | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.35		0.0037
Measurement Input, Entity Credit Risk [Member] | Fuel Oils | Discounted Cash Flow | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.35		0.0037
Measurement Input, Entity Credit Risk [Member] | Fuel Oils | Discounted Cash Flow | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.35		0.0037
Measurement Input, Entity Credit Risk [Member] | Power | Discounted Cash Flow | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.0035		0.0037
Measurement Input, Entity Credit Risk [Member] | Power | Discounted Cash Flow | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.0035		0.0037
Measurement Input, Entity Credit Risk [Member] | Power | Discounted Cash Flow | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.0035		0.0037
Measurement Input, Commodity Forward Price [Member] | Power | Discounted Cash Flow | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MWh			24
Measurement Input, Commodity Forward Price [Member] | Power | Discounted Cash Flow | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MWh			46
Measurement Input, Commodity Forward Price [Member] | Power | Discounted Cash Flow | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MWh			28
Measurement Input, Price Volatility [Member] | Natural Gas | Option Model | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input			0.26
Measurement Input, Price Volatility [Member] | Natural Gas | Option Model | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input			0.46
Measurement Input, Price Volatility [Member] | Natural Gas | Option Model | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input			0.37
Measurement Input, Price Volatility [Member] | Fuel Oils | Option Model | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.20		0.20
Measurement Input, Price Volatility [Member] | Fuel Oils | Option Model | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.34		0.26
Measurement Input, Price Volatility [Member] | Fuel Oils | Option Model | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.25		0.22
Measurement Input, Nodal Basis [Member] | Natural Gas | Discounted Cash Flow | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MMBTU	(1.3)		(1.20)
Measurement Input, Nodal Basis [Member] | Natural Gas | Discounted Cash Flow | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MMBTU	0.3		0.10
Measurement Input, Nodal Basis [Member] | Natural Gas | Discounted Cash Flow | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MMBTU	(0.9)		(1.00)
Measurement Input, Nodal Basis [Member] | Natural Gas | Option Model | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MMBTU			(0.50)
Measurement Input, Nodal Basis [Member] | Natural Gas | Option Model | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MMBTU			(0.30)
Measurement Input, Nodal Basis [Member] | Natural Gas | Option Model | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MMBTU			(0.40)
Measurement Input, Nodal Basis [Member] | Power | Discounted Cash Flow | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MWh	(10)		(10)
Measurement Input, Nodal Basis [Member] | Power | Discounted Cash Flow | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MWh	0		0
Measurement Input, Nodal Basis [Member] | Power | Discounted Cash Flow | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MWh	(2)		(2)
Measurement Input, Quoted Price [Member] | Power | Discounted Cash Flow | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MWh	24
Measurement Input, Quoted Price [Member] | Power | Discounted Cash Flow | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MWh	39
Measurement Input, Quoted Price [Member] | Power | Discounted Cash Flow | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MWh	27
Measurement Input, Auction Pricing [Member] | Power | Discounted Cash Flow | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MW	(898)		(65)
Measurement Input, Auction Pricing [Member] | Power | Discounted Cash Flow | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MW	1,180		1,823
Measurement Input, Auction Pricing [Member] | Power | Discounted Cash Flow | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MW	57		251
Measurement Input, Commodity Future Price [Member] | Power | Fundamental Energy Production Model | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MMBTU	3		3
Measurement Input, Commodity Future Price [Member] | Power | Fundamental Energy Production Model | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MMBTU	3		4
Measurement Input, Commodity Future Price [Member] | Power | Fundamental Energy Production Model | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / MMBTU	3		3
Measurement Input, Escalation Rate [Member] | Power | Fundamental Energy Production Model | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.04		0.05
Measurement Input, Escalation Rate [Member] | Power | Fundamental Energy Production Model | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.04		0.05
Measurement Input, Escalation Rate [Member] | Power | Fundamental Energy Production Model | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input	0.04		0.05
Measurement Input, Estimated Renewable Energy Credit Costs [Member] | Power | Contract Price Allocation | Minimum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / credit	5		5
Measurement Input, Estimated Renewable Energy Credit Costs [Member] | Power | Contract Price Allocation | Maximum
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / credit	7		7
Measurement Input, Estimated Renewable Energy Credit Costs [Member] | Power | Contract Price Allocation | Weighted Average
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Measurement input | $ / credit	6		6

XML

Fair Value Measurements (Schedule Of Carrying Amounts And Estimated Fair Values Of Financial Assets and Liabilities) (Detail) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt	$ 506	$ 484
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	96	68	$ 53	$ 52
Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt	0	39
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	25	7	5	5
Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt	0	62
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	57	41	$ 28	$ 28
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt	506	484
Long-term debt (including current portion)	8,460	7,935
Preferred stock	142	142
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	96	68
Debt Issuance Costs, Net	56	50
Carrying Amount | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Advances to Money Pool	66
Available-for-sale Securities and Held-to-maturity Securities	276	276
Short-term Debt		39
Long-term debt (including current portion)	4,202	3,961
Preferred stock	80	80
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	25	7
Debt Issuance Costs, Net	23	20
Carrying Amount | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Borrowings from Money Pool	31
Short-term Debt		62
Long-term debt (including current portion)	3,113	2,830
Preferred stock	62	62
Fair Value, Concentration of Risk, Cash and Cash Equivalents	57
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents		41
Debt Issuance Costs, Net	27	24
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value	506	484
Investments, Fair Value Disclosure	276	276
Long-term Debt, Fair Value	8,849	8,531
Preferred stock	140	131
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	96	68
Fair Value | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value	0	0
Investments, Fair Value Disclosure	0	0
Long-term Debt, Fair Value	0	0
Preferred stock	0	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	96	68
Fair Value | Significant Other Observable Inputs (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value	506	484
Investments, Fair Value Disclosure	276	276
Long-term Debt, Fair Value	8,411	8,531
Preferred stock	140	131
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	0	0
Fair Value | Significant Other Unobservable Inputs (Level 3)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value	0	0
Investments, Fair Value Disclosure	0	0
Long-term Debt, Fair Value	438	0
Preferred stock	0	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	0	0
Fair Value | Union Electric Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Advances to Money Pool	66
Short-term Debt, Fair Value		39
Investments, Fair Value Disclosure	276	276
Long-term Debt, Fair Value	4,544	4,348
Preferred stock	79	80
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	25	7
Fair Value | Union Electric Company | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Advances to Money Pool	0
Short-term Debt, Fair Value		0
Investments, Fair Value Disclosure	0	0
Long-term Debt, Fair Value	0	0
Preferred stock	0	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	25	7
Fair Value | Union Electric Company | Significant Other Observable Inputs (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Advances to Money Pool	66
Short-term Debt, Fair Value		39
Investments, Fair Value Disclosure	276	276
Long-term Debt, Fair Value	4,544	4,348
Preferred stock	79	80
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	0	0
Fair Value | Union Electric Company | Significant Other Unobservable Inputs (Level 3)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Advances to Money Pool	0
Short-term Debt, Fair Value		0
Investments, Fair Value Disclosure	0	0
Long-term Debt, Fair Value	0	0
Preferred stock	0	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	0	0
Fair Value | Ameren Illinois Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value		62
Borrowings from Money Pool	31
Long-term Debt, Fair Value	3,187	3,028
Preferred stock	61	51
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	57	41
Fair Value | Ameren Illinois Company | Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value		0
Borrowings from Money Pool	0
Long-term Debt, Fair Value	0	0
Preferred stock	0	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	57	41
Fair Value | Ameren Illinois Company | Significant Other Observable Inputs (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value		62
Borrowings from Money Pool	31
Long-term Debt, Fair Value	3,187	3,028
Preferred stock	61	51
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	0	0
Fair Value | Ameren Illinois Company | Significant Other Unobservable Inputs (Level 3)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value		0
Borrowings from Money Pool	0
Long-term Debt, Fair Value	0	0
Preferred stock	0	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 0	$ 0

XML

Related Party Transactions (Schedule of Related Party Transactions) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Related Party Transaction [Line Items]
Operating Revenues	$ 0	$ 0	$ 0	$ 0
Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Revenues	0	0	0	0
Ameren Missouri Power Supply Agreements with Ameren Illinois | Union Electric Company
Related Party Transaction [Line Items]
Operating Revenues	3	6	6	17
Ameren Missouri and Ameren Illinois Rent and Facility Services | Union Electric Company
Related Party Transaction [Line Items]
Operating Revenues	6	6	11	13
Ameren Missouri and Ameren Illinois Rent and Facility Services | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Revenues	1	1	2	2
Ameren Missouri and Ameren Illinois miscellaneous support services | Union Electric Company
Related Party Transaction [Line Items]
Operating Revenues	1	1	1	1
Ameren Missouri and Ameren Illinois miscellaneous support services | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Revenues	1	1	1	1
Total Related Party Operating Revenues [Member] | Union Electric Company
Related Party Transaction [Line Items]
Operating Revenues	9	12	17	30
Total Related Party Operating Revenues [Member] | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Revenues	1	2	2	3
Ameren Illinois Power Supply Agreements with Ameren Missouri | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Expenses	3	6	6	17
Ameren Illinois Transmission Agreements with ATXI | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Expenses	1	1	1	1
Purchased Power | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Expenses	4	7	7	18
Ameren Services Support Services Agreement | Union Electric Company
Related Party Transaction [Line Items]
Operating Expenses	32	34	65	69
Ameren Services Support Services Agreement | Ameren Illinois Company
Related Party Transaction [Line Items]
Operating Expenses	30	34	60	66
Related Party Money Pool Interest | Union Electric Company
Related Party Transaction [Line Items]
Interest Charges	1	1	1	1
Related Party Money Pool Interest | Ameren Illinois Company
Related Party Transaction [Line Items]
Interest Charges	$ 1	$ 1	$ 1	$ 1

XML

Related Party Transactions Narrative (Details) - April 2018 Procurement [Member] - Ameren Illinois Company - Ameren Illinois Power Supply Agreements with Ameren Missouri	3 Months Ended	6 Months Ended
	Jun. 30, 2018 $ / MWh	Jun. 30, 2018 MWh
Related Party Transaction [Line Items]
Long-term Contract for Purchase of Electric Power, Related Party Contract, Fixed Power | MWh		110,000
Long-term Contract for Purchase of Electric Power, Related Party Contract, Fixed Power, Rate | $ / MWh	32

XML

Commitments And Contingencies (Other Obligations) (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($) MWh
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	$ 568
Unrecorded Unconditional Purchase Obligation, Due within Two Years	656
Unrecorded Unconditional Purchase Obligation, Due within Three Years	344
Unrecorded Unconditional Purchase Obligation, Due within Four Years	183
Unrecorded Unconditional Purchase Obligation, Due within Five Years	55
Unrecorded Unconditional Purchase Obligation, Due after Five Years	252
Unrecorded Unconditional Purchase Obligation	2,058
Coal [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	181
Unrecorded Unconditional Purchase Obligation, Due within Two Years	246
Unrecorded Unconditional Purchase Obligation, Due within Three Years	85
Unrecorded Unconditional Purchase Obligation, Due within Four Years	27
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	539
Natural Gas
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	148
Unrecorded Unconditional Purchase Obligation, Due within Two Years	210
Unrecorded Unconditional Purchase Obligation, Due within Three Years	125
Unrecorded Unconditional Purchase Obligation, Due within Four Years	61
Unrecorded Unconditional Purchase Obligation, Due within Five Years	12
Unrecorded Unconditional Purchase Obligation, Due after Five Years	39
Unrecorded Unconditional Purchase Obligation	595
Nuclear Fuel
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	51
Unrecorded Unconditional Purchase Obligation, Due within Two Years	27
Unrecorded Unconditional Purchase Obligation, Due within Three Years	38
Unrecorded Unconditional Purchase Obligation, Due within Four Years	57
Unrecorded Unconditional Purchase Obligation, Due within Five Years	12
Unrecorded Unconditional Purchase Obligation, Due after Five Years	62
Unrecorded Unconditional Purchase Obligation	247
Purchased Power
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	130
Unrecorded Unconditional Purchase Obligation, Due within Two Years	122
Unrecorded Unconditional Purchase Obligation, Due within Three Years	30
Unrecorded Unconditional Purchase Obligation, Due within Four Years	5
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	287
Methane Gas [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	4
Unrecorded Unconditional Purchase Obligation, Due within Three Years	4
Unrecorded Unconditional Purchase Obligation, Due within Four Years	5
Unrecorded Unconditional Purchase Obligation, Due within Five Years	5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	58
Unrecorded Unconditional Purchase Obligation	78
Other Purchased Fuel [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	56
Unrecorded Unconditional Purchase Obligation, Due within Two Years	47
Unrecorded Unconditional Purchase Obligation, Due within Three Years	62
Unrecorded Unconditional Purchase Obligation, Due within Four Years	28
Unrecorded Unconditional Purchase Obligation, Due within Five Years	26
Unrecorded Unconditional Purchase Obligation, Due after Five Years	93
Unrecorded Unconditional Purchase Obligation	312
Union Electric Company
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	295
Unrecorded Unconditional Purchase Obligation, Due within Two Years	344
Unrecorded Unconditional Purchase Obligation, Due within Three Years	201
Unrecorded Unconditional Purchase Obligation, Due within Four Years	128
Unrecorded Unconditional Purchase Obligation, Due within Five Years	48
Unrecorded Unconditional Purchase Obligation, Due after Five Years	211
Unrecorded Unconditional Purchase Obligation	1,227
Union Electric Company | Coal [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	181
Unrecorded Unconditional Purchase Obligation, Due within Two Years	246
Unrecorded Unconditional Purchase Obligation, Due within Three Years	85
Unrecorded Unconditional Purchase Obligation, Due within Four Years	27
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	539
Union Electric Company | Natural Gas
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	22
Unrecorded Unconditional Purchase Obligation, Due within Two Years	38
Unrecorded Unconditional Purchase Obligation, Due within Three Years	30
Unrecorded Unconditional Purchase Obligation, Due within Four Years	14
Unrecorded Unconditional Purchase Obligation, Due within Five Years	5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	17
Unrecorded Unconditional Purchase Obligation	126
Union Electric Company | Nuclear Fuel
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	51
Unrecorded Unconditional Purchase Obligation, Due within Two Years	27
Unrecorded Unconditional Purchase Obligation, Due within Three Years	38
Unrecorded Unconditional Purchase Obligation, Due within Four Years	57
Unrecorded Unconditional Purchase Obligation, Due within Five Years	12
Unrecorded Unconditional Purchase Obligation, Due after Five Years	62
Unrecorded Unconditional Purchase Obligation	247
Union Electric Company | Purchased Power
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	$ 0
Amount of Megawatts | MWh	102
Union Electric Company | Methane Gas [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	$ 2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	4
Unrecorded Unconditional Purchase Obligation, Due within Three Years	4
Unrecorded Unconditional Purchase Obligation, Due within Four Years	5
Unrecorded Unconditional Purchase Obligation, Due within Five Years	5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	58
Unrecorded Unconditional Purchase Obligation	78
Union Electric Company | Other Purchased Fuel [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	39
Unrecorded Unconditional Purchase Obligation, Due within Two Years	29
Unrecorded Unconditional Purchase Obligation, Due within Three Years	44
Unrecorded Unconditional Purchase Obligation, Due within Four Years	25
Unrecorded Unconditional Purchase Obligation, Due within Five Years	26
Unrecorded Unconditional Purchase Obligation, Due after Five Years	74
Unrecorded Unconditional Purchase Obligation	237
Ameren Illinois Company
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	261
Unrecorded Unconditional Purchase Obligation, Due within Two Years	303
Unrecorded Unconditional Purchase Obligation, Due within Three Years	134
Unrecorded Unconditional Purchase Obligation, Due within Four Years	52
Unrecorded Unconditional Purchase Obligation, Due within Five Years	7
Unrecorded Unconditional Purchase Obligation, Due after Five Years	22
Unrecorded Unconditional Purchase Obligation	779
Ameren Illinois Company | Coal [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	0
Ameren Illinois Company | Natural Gas
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	126
Unrecorded Unconditional Purchase Obligation, Due within Two Years	172
Unrecorded Unconditional Purchase Obligation, Due within Three Years	95
Unrecorded Unconditional Purchase Obligation, Due within Four Years	47
Unrecorded Unconditional Purchase Obligation, Due within Five Years	7
Unrecorded Unconditional Purchase Obligation, Due after Five Years	22
Unrecorded Unconditional Purchase Obligation	469
Ameren Illinois Company | Nuclear Fuel
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	0
Ameren Illinois Company | Purchased Power
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	130
Unrecorded Unconditional Purchase Obligation, Due within Two Years	122
Unrecorded Unconditional Purchase Obligation, Due within Three Years	30
Unrecorded Unconditional Purchase Obligation, Due within Four Years	5
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	287
Ameren Illinois Company | Methane Gas [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	0
Ameren Illinois Company | Other Purchased Fuel [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	5
Unrecorded Unconditional Purchase Obligation, Due within Two Years	9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	23
Ameren Illinois Company | April 2018 Procurement [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Long-term Purchase Commitment, Amount	$ 112
Amount of Megawatthours | MWh	3,956,200
Ameren Illinois Company | Zero Emission Credits [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Unrecorded Unconditional Purchase Obligation	$ 57

XML

Commitments And Contingencies (Environmental Matters) (Detail) $ in Millions	Jun. 30, 2018 USD ($) scrubber site	Dec. 31, 2017 USD ($)
Loss Contingencies [Line Items]
Percentage of Rate Base Related to Carbon Dioxide Energy Centers		17.00%
Asset Retirement Obligation	$ 647.0	$ 644.0
Minimum
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	325.0
Maximum
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	425.0
Union Electric Company
Loss Contingencies [Line Items]
Percentage of Rate Base Related to Carbon Dioxide Energy Centers		33.00%
Asset Retirement Obligation	$ 643.0	$ 640.0
Number of Energy Center Scrubbers | scrubber	2
Union Electric Company | Minimum
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	$ 325.0
Union Electric Company | Maximum
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	425.0
Ameren Illinois Company
Loss Contingencies [Line Items]
Asset Retirement Obligation	4.0	$ 4.0
Coal Combustion Residuals Estimate [Member] | Union Electric Company | Minimum
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	300.0
Coal Combustion Residuals Estimate [Member] | Union Electric Company | Maximum
Loss Contingencies [Line Items]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	350.0
Manufactured Gas Plant
Loss Contingencies [Line Items]
Accrual for environmental loss contingencies	$ 165.0
Manufactured Gas Plant | Ameren Illinois Company
Loss Contingencies [Line Items]
Number of remediation sites | site	44
Accrual for environmental loss contingencies	$ 165.0
Manufactured Gas Plant | Ameren Illinois Company | Minimum
Loss Contingencies [Line Items]
Estimate of possible loss	165.0
Manufactured Gas Plant | Ameren Illinois Company | Maximum
Loss Contingencies [Line Items]
Estimate of possible loss	236.0
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
New CCR Rules Estimate
Loss Contingencies [Line Items]
Asset Retirement Obligation	141.0
New CCR Rules Estimate | Union Electric Company
Loss Contingencies [Line Items]
Asset Retirement Obligation	$ 141.0

XML

Callaway Energy Center (Narrative) (Detail) - Nuclear Plant $ in Millions	6 Months Ended
	Jun. 30, 2018 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	6 Months Ended
	Jun. 30, 2018 USD ($)	Jun. 30, 2018 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	12,604,000,000
Maximum Assessments for Single Incidents	127,000,000
Public Liability
Nuclear Waste Matters [Line Items]
Maximum Coverages	13,054,000,000
Maximum Assessments for Single Incidents	127,000,000
Property Damage - Nuclear Electric Insurance Ltd
Nuclear Waste Matters [Line Items]
Maximum Coverages	3,200,000,000
Maximum Assessments for Single Incidents	27,000,000
Replacement Power - Nuclear Electric Insurance Ltd
Nuclear Waste Matters [Line Items]
Maximum Coverages	490,000,000
Maximum Assessments for Single Incidents	7,000,000
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

XML

Retirement Benefits Retirement Benefits (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total non-service cost components	$ 19	$ 10	$ 35	$ 22
Union Electric Company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total non-service cost components	4	6	9	12
Ameren Illinois Company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total non-service cost components	$ 10	$ 1	$ 17	$ 4

XML

Retirement Benefits (Components Of Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total non-service cost components	$ (19)	$ (10)	$ (35)	$ (22)
Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	25	23	50	46
Interest cost	42	45	84	90
Expected return on plan assets	(69)	(65)	(138)	(131)
Prior service cost (benefit)	0	0	0	0
Actuarial loss	18	13	34	27
Total non-service cost components	(9)	(7)	(20)	(14)
Net periodic benefit cost	16	16	30	32
Other Postretirement Benefit Plan, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	5	5	10	10
Interest cost	9	11	20	23
Expected return on plan assets	(19)	(18)	(38)	(37)
Prior service cost (benefit)	(1)	(1)	(2)	(2)
Actuarial loss	(3)	(1)	(3)	(3)
Total non-service cost components	(14)	(9)	(23)	(19)
Net periodic benefit cost	(9)	(4)	(13)	(9)
Union Electric Company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total non-service cost components	(4)	(6)	(9)	(12)
Union Electric Company | Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	6	6	11	12
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)	0	(2)
Ameren Illinois Company
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total non-service cost components	(10)	(1)	(17)	(4)
Ameren Illinois Company | Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost	10	10	19	20
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	$ (9)	$ (3)	$ (13)	$ (7)

XML

Retirement Benefits (Summary Of Benefit Plan Costs Incurred) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 16	$ 16	$ 30	$ 32
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 (Credit)	6	6	11	12
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 (Credit)	10	10	19	20
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 (Credit)	(9)	(4)	(13)	(9)
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 (Credit)		(1)	0	(2)
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 (Credit)	$ (9)	$ (3)	$ (13)	$ (7)

XML

Segment Information (Schedule Of Segment Reporting Information By Segment) (Detail) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) segment	Jun. 30, 2017 USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments | segment			4
External revenues	$ 1,563	$ 1,537	$ 3,148	$ 3,052
Intersegment revenues	0	0	0	0
Net Income (Loss) Available to Common Stockholders, Basic	239	193	390	295
Capital expenditures	533	494	$ 1,112	998
Union Electric Company
Segment Reporting Information [Line Items]
Number of Reportable Segments | segment			1
Ameren Illinois Company
Segment Reporting Information [Line Items]
Number of Reportable Segments | segment			3
Ameren Illinois Company
Segment Reporting Information [Line Items]
External revenues	578	576	$ 1,338	1,279
Intersegment revenues	0	0	0	0
Net Income Available to Common Shareholder	62	57	157	136
Capital expenditures	302	257	602	484
Operating Segments | Union Electric Company
Segment Reporting Information [Line Items]
External revenues	946	922	1,730	1,695
Intersegment revenues	9	12	17	30
Capital expenditures	205	159	454	355
Operating Segments | Ameren Illinois Electric Distribution
Segment Reporting Information [Line Items]
External revenues	386	387	785	771
Intersegment revenues	1	2	2	3
Net Income Available to Common Shareholder	33	33	66	63
Capital expenditures	132	122	254	242
Operating Segments | Ameren Illinois Gas
Segment Reporting Information [Line Items]
External revenues	142	134	453	398
Intersegment revenues	0	0	0	0
Net Income Available to Common Shareholder	7	5	49	38
Capital expenditures	66	58	126	109
Operating Segments | Ameren Transmission
Segment Reporting Information [Line Items]
External revenues	89	92	180	188
Intersegment revenues	14	13	27	19
Net Income Available to Common Shareholder	36	34	73	68
Capital expenditures	130	156	275	290
Operating Segments | Other
Segment Reporting Information [Line Items]
External revenues	0	2	0	0
Intersegment revenues	0	0	0	0
Net Income Available to Common Shareholder	(5)	1	(4)	1
Capital expenditures	(2)	1	5	5
Operating Segments | Ameren Illinois Company | Ameren Illinois Electric Distribution
Segment Reporting Information [Line Items]
External revenues	387	389	787	774
Intersegment revenues	0	0	0	0
Net Income Available to Common Shareholder	33	33	66	63
Capital expenditures	132	122	254	242
Operating Segments | Ameren Illinois Company | Ameren Illinois Gas
Segment Reporting Information [Line Items]
External revenues	142	134	453	398
Intersegment revenues	0	0	0	0
Net Income Available to Common Shareholder	7	5	49	38
Capital expenditures	66	58	126	109
Operating Segments | Ameren Illinois Company | Ameren Illinois Transmission
Segment Reporting Information [Line Items]
External revenues	49	53	98	107
Intersegment revenues	13	12	26	18
Net Income Available to Common Shareholder	22	19	42	35
Capital expenditures	104	77	222	133
Intersegment Eliminations
Segment Reporting Information [Line Items]
External revenues	0	0	0	0
Intersegment revenues	(24)	(27)	(46)	(52)
Net Income Available to Common Shareholder	0	0	0	0
Capital expenditures	2	(2)	(2)	(3)
Intersegment Eliminations | Ameren Illinois Company
Segment Reporting Information [Line Items]
External revenues	0	0	0	0
Intersegment revenues	(13)	(12)	(26)	(18)
Net Income Available to Common Shareholder	0	0	0	0
Capital expenditures	$ 0	$ 0	$ 0	$ 0

XML

Segment Information Segment Information (Disaggregation of Revenue) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 1,563	$ 1,537	$ 3,148	$ 3,052
Revenues from alternative revenue programs	0	12	20	54
Other revenues not from contracts with customers	8	5	33	12
TCJA - Excess Amounts Collected in Rates
Disaggregation of Revenue [Line Items]
TCJA Revenue Reduction	37		47
Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(24)	(27)	(46)	(52)
Electricity
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,396	1,382	2,619	2,589
Electricity | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	653	566	1,204	1,071
Electricity | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	490	461	866	824
Electricity | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	120	112	216	198
Electricity | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	133	243	333	496
Electricity | Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(24)	(26)	(46)	(51)
Electricity | Intersegment Eliminations | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Electricity | Intersegment Eliminations | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Electricity | Intersegment Eliminations | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Electricity | Intersegment Eliminations | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(24)	(26)	(46)	(51)
Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	167	155	529	463
Natural Gas | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	110	94	394	327
Natural Gas | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	32	28	115	95
Natural Gas | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	5	3	13	7
Natural Gas | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	20	30	7	34
Natural Gas | Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	(1)	0	(1)
Natural Gas | Intersegment Eliminations | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Natural Gas | Intersegment Eliminations | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Natural Gas | Intersegment Eliminations | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Natural Gas | Intersegment Eliminations | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	(1)	0	(1)
Ameren Illinois Company
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	578	576	1,338	1,279
Ameren Illinois Company | Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(13)	(12)	(26)	(18)
Ameren Illinois Company | Intersegment Eliminations | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Ameren Illinois Company | Intersegment Eliminations | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Ameren Illinois Company | Intersegment Eliminations | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Ameren Illinois Company | Intersegment Eliminations | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(13)	(12)	(26)	(18)
Ameren Illinois Company | Ameren Illinois Company
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	578	576	1,338	1,279
Revenues from alternative revenue programs	5	19	29	66
Other revenues not from contracts with customers	3	2	14	5
Ameren Illinois Company | Ameren Illinois Company | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	318	292	780	714
Ameren Illinois Company | Ameren Illinois Company | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	152	153	343	341
Ameren Illinois Company | Ameren Illinois Company | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	38	30	79	61
Ameren Illinois Company | Ameren Illinois Company | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	70	101	136	163
Ameren Illinois Company | Electricity
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	436	442	885	881
Ameren Illinois Company | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	142	134	453	398
Operating Segments | Union Electric Company
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	955	934	1,747	1,725
Revenues from alternative revenue programs	(5)	(7)	(9)	(14)
Other revenues not from contracts with customers	5	3	19	7
Operating Segments | Ameren Illinois Electric Distribution
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	387	389	787	774
Revenues from alternative revenue programs	15	16	46	49
Other revenues not from contracts with customers	3	1	13	3
Operating Segments | Ameren Illinois Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	142	134	453	398
Revenues from alternative revenue programs	(5)	1	(8)	12
Other revenues not from contracts with customers	0	1	1	2
Operating Segments | Ameren Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	103	105	207	207
Revenues from alternative revenue programs	(5)	2	(9)	7
Other revenues not from contracts with customers	0	0	0	0
Operating Segments | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	2	0	0
Operating Segments | Electricity | Union Electric Company
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	930	912	1,671	1,659
Operating Segments | Electricity | Union Electric Company | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	432	358	764	644
Operating Segments | Electricity | Union Electric Company | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	364	332	616	562
Operating Segments | Electricity | Union Electric Company | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	87	84	148	142
Operating Segments | Electricity | Union Electric Company | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	47	138	143	311
Operating Segments | Electricity | Ameren Illinois Electric Distribution
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	387	389	787	774
Operating Segments | Electricity | Ameren Illinois Electric Distribution | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	221	208	440	427
Operating Segments | Electricity | Ameren Illinois Electric Distribution | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	126	129	250	262
Operating Segments | Electricity | Ameren Illinois Electric Distribution | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	33	28	68	56
Operating Segments | Electricity | Ameren Illinois Electric Distribution | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	7	24	29	29
Operating Segments | Electricity | Ameren Illinois Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Electricity | Ameren Illinois Gas | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Electricity | Ameren Illinois Gas | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Electricity | Ameren Illinois Gas | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Electricity | Ameren Illinois Gas | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Electricity | Ameren Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	103	105	207	207
Operating Segments | Electricity | Ameren Transmission | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Electricity | Ameren Transmission | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Electricity | Ameren Transmission | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Electricity | Ameren Transmission | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	103	105	207	207
Operating Segments | Electricity | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	2	0	0
Operating Segments | Electricity | Other | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Electricity | Other | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Electricity | Other | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Electricity | Other | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	2	0	0
Operating Segments | Natural Gas | Union Electric Company
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	25	22	76	66
Operating Segments | Natural Gas | Union Electric Company | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	13	10	54	40
Operating Segments | Natural Gas | Union Electric Company | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	6	4	22	16
Operating Segments | Natural Gas | Union Electric Company | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	1	2	2
Operating Segments | Natural Gas | Union Electric Company | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	6	7	(2)	8
Operating Segments | Natural Gas | Ameren Illinois Electric Distribution
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Ameren Illinois Electric Distribution | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Ameren Illinois Electric Distribution | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Ameren Illinois Electric Distribution | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Ameren Illinois Electric Distribution | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Ameren Illinois Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	142	134	453	398
Operating Segments | Natural Gas | Ameren Illinois Gas | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	97	84	340	287
Operating Segments | Natural Gas | Ameren Illinois Gas | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	26	24	93	79
Operating Segments | Natural Gas | Ameren Illinois Gas | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	5	2	11	5
Operating Segments | Natural Gas | Ameren Illinois Gas | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	14	24	9	27
Operating Segments | Natural Gas | Ameren Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Ameren Transmission | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Ameren Transmission | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Ameren Transmission | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Ameren Transmission | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Other | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Other | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Other | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Natural Gas | Other | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Ameren Illinois Company | Ameren Illinois Electric Distribution
Disaggregation of Revenue [Line Items]
Revenues from alternative revenue programs	15	16	46	49
Other revenues not from contracts with customers	3	1	13	3
Operating Segments | Ameren Illinois Company | Ameren Illinois Gas
Disaggregation of Revenue [Line Items]
Revenues from alternative revenue programs	(5)	1	(8)	12
Other revenues not from contracts with customers	0	1	1	2
Operating Segments | Ameren Illinois Company | Ameren Illinois Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	62	65	124	125
Revenues from alternative revenue programs	(5)	2	(9)	5
Other revenues not from contracts with customers	0	0	0	0
Operating Segments | Ameren Illinois Company | Ameren Illinois Transmission | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Ameren Illinois Company | Ameren Illinois Transmission | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Ameren Illinois Company | Ameren Illinois Transmission | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0	0	0
Operating Segments | Ameren Illinois Company | Ameren Illinois Transmission | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	62	65	124	125
Operating Segments | Ameren Illinois Company | Electricity | Ameren Illinois Electric Distribution
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	387	389	787	774
Operating Segments | Ameren Illinois Company | Electricity | Ameren Illinois Electric Distribution | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	221	208	440	427
Operating Segments | Ameren Illinois Company | Electricity | Ameren Illinois Electric Distribution | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	126	129	250	262
Operating Segments | Ameren Illinois Company | Electricity | Ameren Illinois Electric Distribution | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	33	28	68	56
Operating Segments | Ameren Illinois Company | Electricity | Ameren Illinois Electric Distribution | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	7	24	29	29
Operating Segments | Ameren Illinois Company | Natural Gas | Ameren Illinois Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	142	134	453	398
Operating Segments | Ameren Illinois Company | Natural Gas | Ameren Illinois Gas | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	97	84	340	287
Operating Segments | Ameren Illinois Company | Natural Gas | Ameren Illinois Gas | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	26	24	93	79
Operating Segments | Ameren Illinois Company | Natural Gas | Ameren Illinois Gas | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	5	2	11	5
Operating Segments | Ameren Illinois Company | Natural Gas | Ameren Illinois Gas | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 14	$ 24	$ 9	$ 27