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, ~~2017~~2018



¨	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, ~~2017,~~2018, was as follows:



Ameren Corporation		Common stock, $0.01 par value per share – ~~242,634,798~~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	3
	~~Consolidated Statement of~~ and Comprehensive Income	43
	Consolidated Balance Sheet	54
	Consolidated Statement of Cash Flows	65
	Union Electric Company (d/b/a Ameren Missouri)	76
	Statement of Income ~~and Comprehensive Income~~	76
	Balance Sheet	87
	Statement of Cash Flows	98
	Ameren Illinois Company (d/b/a Ameren Illinois)	109
	Statement of Income ~~and Comprehensive Income~~	109
	Balance Sheet	1110
	Statement of Cash Flows	1211
	Note 1. Summary of Significant Accounting Policies	1312
	Note 2. Rate and Regulatory Matters	1517
	Note 3. Short-term Debt and Liquidity	1720
	Note 4. Long-term Debt and Equity Financings	1821
	Note 5. Other Income, ~~and Expenses~~Net	1922
	Note 6. Derivative Financial Instruments	2022
	Note 7. Fair Value Measurements	2224
	Note 8. ~~Related Party~~Related-party Transactions	2730
	Note 9. Commitments and Contingencies	2831
	Note 10. Callaway Energy Center	3135
	Note 11. Retirement Benefits	3236
	Note 12. Segment Information	3337
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3642
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5766
Item 4.	Controls and Procedures	5867

PART II Other Information

Item 1.	Legal Proceedings	5867
Item 1A.	Risk Factors	5968
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5968
Item 6.	Exhibits	6069

Signatures		6170

GLOSSARY OF TERMS AND ABBREVIATIONS

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

~~EMANI~~2017 IRP – ~~European Mutual Association~~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 ~~Nuclear Insurance.~~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, ~~2016,~~2017, filed by the Ameren Companies with the SEC.

~~Westinghouse~~Missouri Senate Bill 564 – ~~Westinghouse Electric Company, LLC.~~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 ~~2017~~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 participating~~Illinois’ participation in a performance-based formula ratemaking ~~process~~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, ~~such as~~or rates, amendments or technical corrections to the ~~increase in Illinois’ corporate income tax rate that became effective in July 2017, or rates~~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~~energy-efficiency programs and the related revenues and performance incentives earned under its MEEIA ~~plans;~~programs, including Ameren Missouri’s proposed customer energy-efficiency plan filed with the MoPSC in June 2018;

Ameren Illinois’ ~~achievement of~~ability to achieve the FEJA electric ~~energy efficiency~~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 ~~return~~returns on equity;

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

the cost and availability of fuel, such as ultra-low-sulfur coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power, ~~zero-emission~~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 ~~the~~any related ~~rate~~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’s~~Callaway energy center’s only NRC-licensed supplier of such ~~assemblies, which is currently in bankruptcy proceedings;~~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 and the application of appropriate accounting rules and~~ guidance;

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

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

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

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

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

the effects of strategic initiatives, including mergers, acquisitions, and divestitures;

•

the impact of current environmental regulations and new, more stringent, or changing requirements, including those related to CO₂, 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;~~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, ~~and~~ returns on benefit plan ~~assets;~~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 ~~cyber attacks,~~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, ~~data~~employee, financial, and ~~account~~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.

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,
2017 2016 2017 2016
Operating Revenues:
Electric $ 1,383
$ 1,274
$ 2,589
$ 2,376
Natural gas 155
153
463
485
Total operating revenues 1,538
1,427
3,052
2,861
Operating Expenses:
Fuel 189
166
395
369
Purchased power 149
135
329
273
Natural gas purchased for resale 41
41
171
193
Other operations and maintenance 422
435
827
835
Depreciation and amortization 222
210
443
417
Taxes other than income taxes 117
115
235
229
Total operating expenses 1,140
1,102
2,400
2,316
Operating Income 398
325
652
545
Other Income and Expenses:
Miscellaneous income 14
16
29
36
Miscellaneous expense 5
6
14
13
Total other income 9
10
15
23
Interest Charges 99
95
198
190
Income Before Income Taxes 308
240
469
378
Income Taxes 114
92
171
123
Net Income 194
148
298
255
Less: Net Income Attributable to Noncontrolling Interests 1
1
3
3
Net Income Attributable to Ameren Common Shareholders $ 193
$ 147
$ 295
$ 252

Earnings per Common Share – Basic and Diluted $ 0.79
$ 0.61
$ 1.21
$ 1.04

Dividends per Common Share $ 0.44
$ 0.425
$ 0.88
$ 0.85
Average Common Shares Outstanding – Basic 242.6
242.6
242.6
242.6

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

~~AMEREN CORPORATION~~

~~CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME~~

~~(Unaudited) (In millions)~~


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016		2017		2016		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	$	194	$	148	$	298	$	255	240			194		393			298
Other Comprehensive Income, Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes of $1, $3, $1 and $4, respectively	2		4		2		2
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	196		152		300		257		238			196		392			300
Less: Comprehensive Income Attributable to Noncontrolling Interests	1		1		3		3		1			1		3			3
Comprehensive Income Attributable to Ameren Common Shareholders	$	195	$	151	$	297	$	254	$	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.

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

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


	June 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
ASSETS
Current Assets:
Cash and cash equivalents	$	10		$	9		$	29		$	10
Accounts receivable – trade (less allowance for doubtful accounts of $21 and $19, respectively)	446			437
Accounts receivable – trade (less allowance for doubtful accounts of $25 and $19, respectively)							560			445
Unbilled revenue	334			295			371			323
Miscellaneous accounts receivable	77			63			74			70
Inventories	512			527			475			522
Current regulatory assets	95			149			104			144
Other current assets	97			113			72			98
Total current assets	1,571			1,593			1,685			1,612
Property, Plant, and Equipment, Net	20,589			20,113			21,998			21,466
Investments and Other Assets:
Nuclear decommissioning trust fund	651			607			714			704
Goodwill	411			411			411			411
Regulatory assets	1,506			1,437			1,205			1,230
Other assets	526			538			626			522
Total investments and other assets	3,094			2,993			2,956			2,867
TOTAL ASSETS	$	25,254		$	24,699		$	26,639		$	25,945
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	578		$	681		$	847		$	841
Short-term debt	892			558			506			484
Accounts and wages payable	522			805			565			902
Taxes accrued	122			46			139			52
Interest accrued	104			93			109			99
Customer deposits	108			107			114			108
Current regulatory liabilities	141			110			133			128
Other current liabilities	298			274			298			326
Total current liabilities	2,765			2,674			2,711			2,940
Long-term Debt, Net	6,821			6,595			7,613			7,094
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	4,444			4,264			2,584			2,506
Accumulated deferred investment tax credits	52			55			46			49
Regulatory liabilities	2,003			1,985			4,540			4,387
Asset retirement obligations	634			635			641			638
Pension and other postretirement benefits	758			769			545			545
Other deferred credits and liabilities	477			477			431			460
Total deferred credits and other liabilities	8,368			8,185			8,787			8,585
Commitments and Contingencies (Notes 2, 4, 9, and 10)
Commitments and Contingencies (Notes 2, 9, and 10)
Ameren Corporation Shareholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – 242.6 shares outstanding	2			2
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	5,528			5,556			5,576			5,540
Retained earnings	1,649			1,568			1,827			1,660
Accumulated other comprehensive loss	(21		)	(23		)	(19		)	(18		)
Total Ameren Corporation shareholders’ equity	7,158			7,103			7,386			7,184
Noncontrolling Interests	142			142			142			142
Total equity	7,300			7,245			7,528			7,326
TOTAL LIABILITIES AND EQUITY	$	25,254		$	24,699		$	26,639		$	25,945

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

													AMEREN CORPORATION	CONSOLIDATED STATEMENT OF CASH FLOWS	(Unaudited) (In millions)
	Six Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2018			2017
Cash Flows From Operating Activities:
Net income	$	298		$	255		$	393		$	298
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	433			419			463			433
Amortization of nuclear fuel	48			38			48			48
Amortization of debt issuance costs and premium/discounts	11			11			11			11
Deferred income taxes and investment tax credits, net	175			134			81			175
Allowance for equity funds used during construction	(10		)	(13		)	(14		)	(10		)
Share-based compensation costs	8			12
Stock-based compensation costs							10			8
Other	(5		)	(7		)	11			(5		)
Changes in assets and liabilities:
Receivables	(54		)	(111		)	(170		)	(54		)
Inventories	14			23			46			14
Accounts and wages payable	(183		)	(200		)	(209		)	(183		)
Taxes accrued	83			80			105			83
Regulatory assets and liabilities	(4		)	108			83			(4		)
Assets, other	22			24			8			22
Liabilities, other	21			(14		)	(50		)	21
Pension and other postretirement benefits	6			4			4			6
Net cash provided by operating activities	863			763			820			863
Cash Flows From Investing Activities:
Capital expenditures	(998		)	(1,000		)	(1,112		)	(998		)
Nuclear fuel expenditures	(50		)	(24		)	(16		)	(50		)
Purchases of securities – nuclear decommissioning trust fund	(213		)	(201		)	(129		)	(161		)
Sales and maturities of securities – nuclear decommissioning trust fund	204			192			122			152
Other	(2		)	(2		)	6			(2		)
Net cash used in investing activities	(1,059		)	(1,035		)	(1,129		)	(1,059		)
Cash Flows From Financing Activities:
Dividends on common stock	(214		)	(206		)	(223		)	(214		)
Dividends paid to noncontrolling interest holders	(3		)	(3		)	(3		)	(3		)
Short-term debt, net	334			477			21			334
Maturities of long-term debt	(425		)	(389		)	(323		)	(425		)
Issuances of long-term debt	549			149			853			549
Share-based payments	(39		)	(32		)
Capital issuance costs	(4		)	(1		)
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		)	(2		)	—			(1		)
Net cash provided by (used in) financing activities	197			(7		)
Net change in cash and cash equivalents	1			(279		)
Cash and cash equivalents at beginning of year	9			292
Cash and cash equivalents at end of period	$	10		$	13
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.

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

STATEMENT OF INCOME ~~AND COMPREHENSIVE INCOME~~

(Unaudited) (In millions)


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016		2018		2017		2018		2017
Operating Revenues:
Electric	$	913	$	844	$	1,659	$	1,538	$	930	$	912	$	1,671	$	1,659
Natural gas	22		23		66		70		25		22		76		66
Total operating revenues	935		867		1,725		1,608		955		934		1,747		1,725
Operating Expenses:
Fuel	189		166		395		369		186		189		374		395
Purchased power	68		50		159		92		40		69		82		160
Natural gas purchased for resale	5		6		25		27		8		5		32		25
Other operations and maintenance	219		238		431		450		241		224		473		443
Depreciation and amortization	132		127		265		254		138		132		274		265
Taxes other than income taxes	85		83		160		156		84		85		164		160
Total operating expenses	698		670		1,435		1,348		697		704		1,399		1,448
Operating Income	237		197		290		260		258		230		348		277
Other Income and Expenses:
Miscellaneous income	11		9		23		24
Miscellaneous expense	2		2		4		4
Total other income	9		7		19		20
Other Income, Net									16		16		29		32
Interest Charges	53		53		107		105		51		53		102		107
Income Before Income Taxes	193		151		202		175		223		193		275		202
Income Taxes	72		58		75		67		54		72		67		75
Net Income	121		93		127		108		169		121		208		127
Other Comprehensive Income	—		—		—		—
Comprehensive Income	$	121	$	93	$	127	$	108


Net Income	$	121	$	93	$	127	$	108
Preferred Stock Dividends	1		1		2		2		1		1		2		2
Net Income Available to Common Shareholder	$	120	$	92	$	125	$	106	$	168	$	120	$	206	$	125

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

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

BALANCE SHEET

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


	June 30, 2017		December 31, 2016		June 30, 2018		December 31, 2017
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	—	$	17	$	—
Advances to money pool	—		161		66		—
Accounts receivable – trade (less allowance for doubtful accounts of $8 and $7, respectively)	212		187
Accounts receivable – trade (less allowance for doubtful accounts of $9 and $7, respectively)					285		200
Accounts receivable – affiliates	15		12		23		11
Unbilled revenue	230		154		256		165
Miscellaneous accounts receivable	34		14		55		35
Inventories	399		392		380		388
Current regulatory assets	17		35		48		56
Other current assets	43		49		42		50
Total current assets	950		1,004		1,172		905
Property, Plant, and Equipment, Net	11,497		11,478		11,835		11,751
Investments and Other Assets:
Nuclear decommissioning trust fund	651		607		714		704
Regulatory assets	590		619		367		395
Other assets	317		327		304		288
Total investments and other assets	1,558		1,553		1,385		1,387
TOTAL ASSETS	$	14,005	$	14,035	$	14,392	$	14,043
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	185	$	431	$	534	$	384
Short-term debt	60		—		—		39
Accounts and wages payable	208		444		226		475
Accounts payable – affiliates	122		68		125		60
Taxes accrued	113		30		110		30
Interest accrued	67		54		69		54
Current regulatory liabilities	29		12		50		19
Other current liabilities	130		123		107		103
Total current liabilities	914		1,162		1,221		1,164
Long-term Debt, Net	3,781		3,563		3,668		3,577
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	3,030		3,013		1,614		1,650
Accumulated deferred investment tax credits	50		53		45		48
Regulatory liabilities	1,255		1,215		2,754		2,664
Asset retirement obligations	629		629		637		634
Pension and other postretirement benefits	287		291		209		213
Other deferred credits and liabilities	16		19		7		12
Total deferred credits and other liabilities	5,267		5,220		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		511		511
Other paid-in capital, principally premium on common stock	1,828		1,828		1,858		1,858
Preferred stock	80		80		80		80
Retained earnings	1,624		1,671		1,788		1,632
Total shareholders’ equity	4,043		4,090		4,237		4,081
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	14,005	$	14,035	$	14,392	$	14,043

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

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

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Six Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2018			2017
Cash Flows From Operating Activities:
Net income	$	127		$	108		$	208		$	127
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	255			257			265			255
Amortization of nuclear fuel	48			38			48			48
Amortization of debt issuance costs and premium/discounts	3			3			3			3
Deferred income taxes and investment tax credits, net	13			66			(24		)	13
Allowance for equity funds used during construction	(9		)	(10		)	(11		)	(9		)
Other	3			—			10			3
Changes in assets and liabilities:
Receivables	(124		)	(103		)	(205		)	(124		)
Inventories	(7		)	(9		)	8			(7		)
Accounts and wages payable	(169		)	(174		)	(160		)	(169		)
Taxes accrued	153			80			152			153
Regulatory assets and liabilities	57			55			106			57
Assets, other	19			14			(2		)	19
Liabilities, other	24			37			11			24
Pension and other postretirement benefits	3			2			3			3
Net cash provided by operating activities	396			364			412			396
Cash Flows From Investing Activities:
Capital expenditures	(355		)	(353		)	(454		)	(355		)
Nuclear fuel expenditures	(50		)	(24		)	(16		)	(50		)
Purchases of securities – nuclear decommissioning trust fund	(213		)	(201		)	(129		)	(161		)
Sales and maturities of securities – nuclear decommissioning trust fund	204			192			122			152
Money pool advances, net	161			36			(66		)	161
Other	—			(4		)
Net cash used in investing activities	(253		)	(354		)	(543		)	(253		)
Cash Flows From Financing Activities:
Dividends on common stock	(172		)	(210		)	(50		)	(172		)
Dividends on preferred stock	(2		)	(2		)	(2		)	(2		)
Short-term debt, net	60			77			(39		)	60
Maturities of long-term debt	(425		)	(260		)	(179		)	(425		)
Issuances of long-term debt	399			149			423			399
Capital contribution from parent	—			38
Capital issuance costs	(3		)	(1		)
Net cash used in financing activities	(143		)	(209		)
Net change in cash and cash equivalents	—			(199		)
Cash and cash equivalents at beginning of year	—			199
Cash and cash equivalents at end of period	$	—		$	—
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.

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

STATEMENT OF INCOME ~~AND COMPREHENSIVE INCOME~~

(Unaudited) (In millions)


	Three Months Ended June 30,					Six Months Ended June 30,						Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016			2017			2016			2018		2017		2018		2017
Operating Revenues:
Electric	$	441	$	411		$	880		$	803		$	436	$	442	$	885	$	881
Natural gas	134		131			398			416			142		134		453		398
Other	1		—			1			—
Total operating revenues	576		542			1,279			1,219			578		576		1,338		1,279
Operating Expenses:
Purchased power	87		90			188			194			105		87		229		188
Natural gas purchased for resale	36		35			146			166			43		36		190		146
Other operations and maintenance	210		200			407			394			196		212		395		412
Depreciation and amortization	85		80			168			157			94		85		184		168
Taxes other than income taxes	28		30			68			68			35		28		76		68
Total operating expenses	446		435			977			979			473		448		1,074		982
Operating Income	130		107			302			240			105		128		264		297
Other Income and Expenses:
Miscellaneous income	3		6			6			11
Miscellaneous expense	2		3			8			8
Total other income (expense)	1		3			(2		)	3
Other Income, Net												13		3		19		3
Interest Charges	36		35			73			70			37		36		74		73
Income Before Income Taxes	95		75			227			173			81		95		209		227
Income Taxes	37		29			89			67			18		37		50		89
Net Income	58		46			138			106			63		58		159		138
Other Comprehensive Loss, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $-, $-, $- and $(1), respectively	—		(1		)	—			(2		)
Comprehensive Income	$	58	$	45		$	138		$	104


Net Income	$	58	$	46		$	138		$	106
Preferred Stock Dividends	1		1			2			2			1		1		2		2
Net Income Available to Common Shareholder	$	57	$	45		$	136		$	104		$	62	$	57	$	157	$	136

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

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

BALANCE SHEET

(Unaudited) (In millions)


	June 30, 2017		December 31, 2016		June 30, 2018		December 31, 2017
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	—	$	—	$	—
Accounts receivable – trade (less allowance for doubtful accounts of $13 and $12, respectively)	219		242
Accounts receivable – trade (less allowance for doubtful accounts of $16 and $12, respectively)					251		234
Accounts receivable – affiliates	69		10		21		9
Unbilled revenue	104		141		115		158
Miscellaneous accounts receivable	14		22		29		35
Inventories	114		135		95		134
Current regulatory assets	75		108		55		87
Other current assets	11		25		10		15
Total current assets	606		683		576		672
Property, Plant, and Equipment, Net	7,780		7,469		8,716		8,293
Investments and Other Assets:
Goodwill	411		411		411		411
Regulatory assets	907		816		822		822
Other assets	97		95		246		147
Total investments and other assets	1,415		1,322		1,479		1,380
TOTAL ASSETS	$	9,801	$	9,474	$	10,771	$	10,345
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	394	$	250	$	313	$	457
Short-term debt	159		51		—		62
Borrowings from money pool					31		—
Accounts and wages payable	236		264		291		337
Accounts payable – affiliates	55		63		44		70
Taxes accrued	7		16		15		19
Interest accrued	31		33		30		33
Customer deposits	69		69		75		69
Current environmental remediation	37		38		43		42
Current regulatory liabilities	95		78		65		92
Other current liabilities	128		109		150		177
Total current liabilities	1,211		971		1,057		1,358
Long-term Debt, Net	2,195		2,338		2,800		2,373
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,748		1,631		1,045		1,021
Accumulated deferred investment tax credits	2		2
Regulatory liabilities	745		768		1,689		1,629
Pension and other postretirement benefits	350		346		292		285
Environmental remediation	152		162		123		134
Other deferred credits and liabilities	228		222		218		235
Total deferred credits and other liabilities	3,225		3,131		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	2,005		2,005		2,093		2,013
Preferred stock	62		62		62		62
Retained earnings	1,103		967		1,392		1,235
Total shareholders’ equity	3,170		3,034		3,547		3,310
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	9,801	$	9,474	$	10,771	$	10,345

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

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

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Six Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2018			2017
Cash Flows From Operating Activities:
Net income	$	138		$	106		$	159		$	138
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	168			156			184			168
Amortization of debt issuance costs and premium/discounts	7			7			7			7
Deferred income taxes and investment tax credits, net	116			65			13			116
Other	—			(6		)	(3		)	—
Changes in assets and liabilities:
Receivables	70			(5		)	23			70
Inventories	20			32			38			20
Accounts and wages payable	(17		)	(20		)	(35		)	(17		)
Taxes accrued	(68		)	(14		)	(23		)	(68		)
Regulatory assets and liabilities	(54		)	48			(20		)	(54		)
Assets, other	3			11			4			3
Liabilities, other	(10		)	(1		)	(58		)	(10		)
Pension and other postretirement benefits	2			3			(2		)	2
Net cash provided by operating activities	375			382			287			375
Cash Flows From Investing Activities:
Capital expenditures	(484		)	(442		)	(602		)	(484		)
Other	4			4			3			4
Net cash used in investing activities	(480		)	(438		)	(599		)	(480		)
Cash Flows From Financing Activities:
Dividends on common stock	—			(60		)
Dividends on preferred stock	(2		)	(2		)	(2		)	(2		)
Short-term debt, net	108			177			(62		)	108
Money pool borrowings, net							31			—
Maturities of long-term debt	—			(129		)	(144		)	—
Issuances of long-term debt							430			—
Debt issuance costs							(5		)	—
Capital contribution from parent							80			—
Other	(1		)	(1		)	—			(1		)
Net cash provided by (used in) financing activities	105			(15		)
Net change in cash and cash equivalents	—			(71		)
Cash and cash equivalents at beginning of year	—			71
Cash and cash equivalents at end of period	$	—		$	—
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.

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, ~~2017~~2018

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company ~~under PUHCA 2005. Ameren’s~~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 ~~Ameren Missouri, Ameren Illinois, and ATXI,~~ are ~~described~~listed below. Ameren also has other subsidiaries that conduct other activities, such as ~~the provision of~~providing shared services. Ameren ~~is also evaluating~~evaluates competitive electric transmission investment opportunities ~~outside of MISO~~ as they arise.

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

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

ATXI operates a FERC rate-regulated electric transmission business. ATXI is developing MISO-approved electric transmission projects, including the Illinois Rivers ~~Spoon River,~~ and Mark Twain ~~projects.~~

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. ~~Also see~~

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 ~~Glossary~~primary beneficiary of ~~Terms and Abbreviations at~~these investments because it does not have the ~~front~~power to direct matters that most significantly affect the activities of ~~this report and~~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 ~~the Form 10-K.~~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 ~~statement~~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. See Note 2 – Rate and Regulatory Matters for information regarding the 2017 change in Ameren Illinois' method used to recognize interim period revenue in connection with the revenue decoupling provisions of the FEJA. These financial statements should be read in conjunction with the financial statements and ~~the~~accompanying notes ~~thereto~~ included in the Form 10-K.

~~Discontinued operations were immaterial~~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 ~~all periods~~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 ~~financial statements. As such,~~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 ~~“Assets~~trust.

Restricted cash included in Ameren’s and Ameren Illinois’ other assets primarily represents amounts in a trust fund restricted for the use of ~~discontinued operations”~~funding certain asbestos-related claims and ~~“Liabilities~~amounts collected under a cost recovery rider that are restricted for use in the procurement of ~~discontinued operations” included~~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, ~~2016~~2017, "Other current liabilities" on Ameren's and Ameren Illinois' balance ~~sheet have been reclassified in this report to “Other current assets”~~sheets included payables for purchased receivables of $40 million and ~~“Other current liabilities,”~~$31 million, respectively. ~~See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of~~

For the ~~Form 10-K for additional information.~~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, ~~2017:~~2018:


	Ameren Missouri				Ameren Illinois^(a)			Ameren				Ameren Missouri				Ameren Illinois^(a)		Ameren
Balance at December 31, 2016	$	644		^(b)	$	6		$	650		^(b)
Balance at December 31, 2017												$	640		^(b)	$	4	$	644		^(b)
Liabilities settled	(1		)		(c)			(1		)		(2		)		(c)		(2		)
Accretion^(d)	13				(c)			13				14				(c)		14
Change in estimates^(e)	(12		)		(1		)	(13		)		(9		)		—		(9		)
Balance at June 30, 2017	$	644		^(b)	$	5		$	649		^(b)
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 ~~$15~~$6 million in “Other current liabilities” on the balance sheet as of both December 31, ~~2016~~2017, and June 30, ~~2017,~~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 ~~related~~due to ~~extending~~a reduction in the ~~remediation period~~cost estimate for closure of certain CCR storage facilities.

~~Share-based~~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

~~A summary of~~The following table summarizes Ameren's nonvested performance share ~~units at~~ ~~June 30, 2017~~,unit and ~~changes during~~restricted stock unit activity for the six months ended June 30, ~~2017~~2018~~, under the 2014 Incentive Plan are presented below:~~:

Performance Share Units
Share Units Weighted-average Fair Value per Share Unit
Nonvested at January 1, 2017 1,059,639
$ 48.04
Granted^(a)
498,940
59.16
Forfeitures (38,521 ) 52.40
Vested^(b)
(5,992 ) 52.88
Nonvested at June 30, 2017 1,514,066
$ 51.57



	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)	~~Performance~~Does not include 712,572 undistributed vested performance share ~~units granted to certain executive and nonexecutive officers and other eligible employees under the 2014 Incentive Plan.~~units.

(b)

~~Performance share~~Undistributed vested units are awards that vested due to ~~the~~ attainment of retirement eligibility by certain ~~employees. Actual~~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 measurement~~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 ~~awarded~~granted in ~~2017 under the 2014 Incentive Plan~~2018 was determined to be $~~59.16~~62.88, which was based on Ameren’s closing common share price of $~~52.46~~58.99 at December 31, ~~2016~~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, ~~2017,~~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 ~~1.47%~~1.98%, and volatility of 15% to ~~21%~~23% for the peer ~~group,~~group.

Restricted Stock Units

Restricted stock units vest and ~~Ameren’s attainment~~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 ~~three-year average earnings per~~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 ~~threshold during~~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 ~~period.~~obligations based on the relative standalone selling price.

~~Operating Revenue~~

~~The Ameren Companies record operating revenue for electric or~~Electric and natural gas ~~service~~retail distribution revenues are earned when itthe commodity is delivered to our customers. We accrue an estimate of electric and natural gas retail distribution revenues for service ~~rendered~~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 ~~qualifying as~~that are alternative revenue programs, ~~such as revenue requirement reconciliations, the Ameren Companies~~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 ~~certain~~from their customers excise taxes, ~~from customers~~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 levied on Ameren Missouri’s electric and natural gas businesses and on Ameren Illinois’ natural gas business and~~ are recorded gross in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” on the ~~statement~~statements of ~~income or the statement of income and comprehensive~~ income. ~~Excise taxes for electric service in Illinois are levied on the customer and therefore are not included in Ameren Illinois’ revenues and expenses.~~ The following table presents 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, ~~2017~~2018 and ~~2016~~2017:


	Three Months				Six Months				Three Months					Six Months
	2017		2016		2017		2016		2018		2017			2018		2017
Ameren Missouri	$	40	$	40	$	71	$	70	$	46	$	40		$	80	$	71
Ameren Illinois	11		11		30		31		28		23		^(a)	63		57		^(a)
Ameren	$	51	$	51	$	101	$	101	$	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

~~Earnings Per Share~~

~~There were no material differences between Ameren’s basic and diluted earnings per share amounts~~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, ~~2017~~2018 and ~~2016. The assumed settlement~~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 ~~dilutive~~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 ~~had an immaterial impact on earnings per share.~~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, ~~2017~~2018 and ~~2016.~~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

~~Income Taxes~~

~~In July 2017,~~restricted cash. Our adoption of the ~~Illinois legislature passed a bill that increased~~guidance on the ~~state's corporate income tax rate from 7.75% to 9.5% as~~recognition and measurement of ~~July 1, 2017. The bill made the increase in the state’s corporate income tax~~rate, which was previously scheduled to decrease to 7.3% in 2025, permanent. Ameren's consolidated 2017 net income is expected to decrease by $15 million, including an expense of $14 million at Ameren (parent), due to the revaluation of accumulated deferred taxesfinancial assets and ~~the estimated state apportionment of such taxes. Beyond this decrease, Ameren does~~financial liabilities did not ~~expect this tax increase to~~ have a material impact on ~~its consolidated net income prospectively. The tax increase is not expected to materially impact the earnings~~our results of the Ameren Illinois Electric Distribution, Ameren Transmission, nor Ameren Illinois Transmission segments since these businesses operate under formula ratemaking frameworks. The tax increase is expected to unfavorably affect 2017 net income of the Ameren Illinois Natural Gas segment by less than $1 million. In addition, in the third quarter of 2017, Ameren’s and Ameren Illinois’ accumulated deferred tax balances will be revalued using the state’s new corporate income tax rate, which is expected to result in a net increase to the liability balances of $97 million and $79 million, respectively. These increased liabilities will be offset by a regulatory asset, as well as income tax expense, as discussed above.operations or financial position.

~~Accounting and Reporting Developments~~

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

~~Revenue~~the reclassification of certain tax effects from ~~Contracts with Customers~~

In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The underlying principle of the guidance is that an entity will recognize revenue for the transfer of promised goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance requires additional disclosures to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, as well as separate presentation of alternative revenue programs on the income statement. Entities can apply the guidance to each reporting period presented (the full retrospective method) or by recording a cumulative effect adjustment to retained earnings in the period of initial adoption (the modified retrospective method).

We have substantially completed the evaluation of our contracts and do not expect material changes to the amount or timing of revenue recognition. We currently plan to apply the guidance using the full retrospective method and to include disaggregated revenue disclosures by segment and customer class in the combined notes to the financial statements in the first quarter of 2018. We will finalize our contract assessments and our selection of transition method by the end of 2017.

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

In March 2017, the FASB issued authoritative guidance that requires an entity to retrospectively report the service cost component of net benefit cost in the same line item(s) as other compensation costs arising from services rendered by employees during the periodand to present the other components of net benefit cost in the income statement separately from the service cost component, and outside of operating income. The guidance also requires that an entity only capitalize the service cost component as part of an asset such as inventory or property, plant, and equipment on a prospective basis. Previously, all of the net benefit cost components were eligible for capitalization. The adoption of this guidance in the first quarter of 2018 may result in the recognition of new regulatory assets or liabilities related to the recovery or return of the non-service cost components of net benefit cost. See Note 11 – Retirement Benefits for the components of net benefit cost. We are currently assessing the impacts of this guidance on our results of operations, financial position, and disclosures.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

~~March 2017~~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 ~~Rate Order~~

~~In March 2017,~~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 ~~issued an order approving~~to authorize a ~~unanimous stipulation and agreement~~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 ~~2016~~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. 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. ~~The order resulted~~

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 ~~$3.4 billion revenue requirement, which is~~regulatory rate review, PISA deferrals would be added to rate base prospectively and earn a ~~$92 million increase in~~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 ~~revenue requirement~~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 ~~compared~~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 ~~its prior revenue requirement established~~issue an order in the ~~MoPSC's April 2015 electric rate order.~~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 ~~new rates, base level of expenses,~~facility is expected to be located in northeastern Missouri and ~~amortizations became effective on April 1, 2017.~~to be completed in

2020. The ~~order authorized~~acquisition is subject to certain conditions, including the ~~continued use~~issuance of the FAC and the regulatory tracking mechanisms for pension and postretirement benefits, uncertain income tax positions, and renewable energy standards that the MoPSC authorized in earlier electric rate orders. These regulatory tracking mechanisms provide for a base level of expense to be reflected in Ameren Missouri’s base electric rates with differences in the actual expenses incurred recorded as a regulatory asset or liability. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs decreased by $54 million from the base level established in the MoPSC's April 2015 electric rate order. Changes in amortizations and the base level of expenses for the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, reduced expenses by $26 million from the base levels established in the MoPSC's April 2015 electric rate order.

~~ATXI’s Mark Twain Project~~

~~The Mark Twain project is a MISO-approved transmission line to be located in northeast Missouri. In April 2016, the MoPSC granted ATXI~~ a certificate of convenience and necessity by the MoPSC, obtaining a MISO transmission interconnection agreement, and approval by the FERC. Ameren Missouri has filed for the ~~Mark Twain project conditioned upon ATXI obtaining county assents~~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 ~~road crossings. None~~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 ~~five county commissions have~~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, ~~ATXI’s requests~~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 ~~assents.~~MEEIA program costs and its lost revenues. In ~~October~~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 ~~ATXI filed suit~~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 ~~circuit courts for each~~first quarter of 2018 relating to the ~~five counties to obtain the assents for the original project route.~~ MEEIA 2016 performance incentive.

In July ~~2017, ATXI withdrew its lawsuit against one of~~2018, the ~~counties. The timing of~~Missouri Supreme Court overturned a ~~decision in each of the other four lawsuits is uncertain. In March 2017, the MoPSC’s April~~ 2016 ~~order was vacated~~decision by the Missouri Court of Appeals, Western District, which ~~ruled that~~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 ~~could not lawfully grant~~is required to issue a ~~certificate of convenience and necessity conditioned upon ATXI obtaining the assents. In the second quarter of 2017, ATXI appealed the March 2017 Court of Appeals decision to~~revised order consistent with the Missouri Supreme ~~Court, which subsequently declined~~Court’s ruling; however, there is no deadline to ~~hear~~issue such order. Upon issuance of the ~~appeal.~~

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

~~ATXI plans to complete the project in late 2019; however, delays in obtaining the assents and approval from the MoPSC could delay completion.~~recognize an additional $9 million MEEIA 2013 performance incentive.

Illinois

~~IEIMA & FEJA~~Electric Distribution Service Rates

~~Under~~In April 2018, Ameren Illinois ~~law,~~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 million increase in Ameren Illinois’ electric distribution service rates ~~are subject~~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 ~~annual~~increase to include the 2017 revenue requirement reconciliation ~~to its actual recoverable costs and allowed return on equity. This revenue requirement reconciliation qualifies as an alternative revenue program under GAAP. Each year, Ameren Illinois records~~adjustment. It also includes a ~~regulatory asset or a regulatory liability and a corresponding increase or~~ decrease ~~to operating revenues~~ for ~~any differences between~~ the ~~revenue requirement reflected in customer rates for that year and its estimate~~conclusion of the probable increase or decrease in the revenue requirement expected to ultimately be approved by the ICC based on that year's actual recoverable costs incurred and investment return. As of June 30, 2017, Ameren Illinois had recorded regulatory assets of $24 million to reflect its 2016 revenue requirement reconciliation adjustment, which ~~was included~~will be fully collected from customers in 2018, consistent with the ~~April~~ICC’s December 2017 ~~formula rate~~annual update ~~discussed below, and $40 million for the approved 2015 revenue requirement reconciliation adjustment, each with interest.~~filing order. An ICC decision in this proceeding is expected by December 2018. As of June 30, ~~2017,~~2018, Ameren Illinois had recorded a regulatory asset of ~~$76~~$62 million to reflect the difference between Ameren Illinois’ estimate of its ~~2017~~2018 revenue requirement and the revenue requirement reflected in customer rates, including interest.

Electric Customer Energy-Efficiency Investments

In ~~April 2017,~~June 2018, Ameren Illinois filed ~~with the ICC~~ its annual electric ~~distribution service~~customer energy-efficiency formula rate update to establish the revenue requirement to be used for ~~2018 rates. In June 2017,~~2019 rates with the ICC staff submitted its calculation of the revenue requirement, which Ameren Illinois supported in its revised July 2017 filing, and recommended a decrease to the electric distribution service revenue requirement.ICC. Pending ICC approval, this update filing will result in ~~a $17~~2019 rates for electric customer energy-efficiency investments of $34 million, ~~decrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2018. This update reflects~~which represents an increase toof $20 million from the annual formula rate based on 2016 actual costs and expected net plant additions for 2017, as well as an increase to include the 2016 revenue requirement reconciliation adjustment. The increases in the update filing are more than offset by a decrease for the conclusion of the 2015 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2017, consistent with the ICC’s December 2016 annual update filing order.2018 rates. An ICC decision regarding the revenue requirement to be used for customer rates in ~~2018~~2019 is expected by December ~~2017.~~2018.

~~The FEJA revised certain portions of~~Income Tax Regulatory Mechanisms

In February 2018, the ~~IEIMA, including extending the IEIMA formula ratemaking process through 2022 and clarifying that~~ICC granted Ameren Illinois’ request, filed in January 2018, to establish a ~~common equity ratio of up~~rider to ~~and including, 50% is prudent. Beginning in 2017, the FEJA provides that~~reduce Ameren ~~Illinois will recover, within the following two years, its~~Illinois’ electric distribution revenue requirement for a given year, independent of actual sales volumes. Prior to the FEJA, Ameren Illinois’ interim period revenue recognition was volume-based, as revenues were affected by the timing of sales volumes due to seasonal rates and changes in volumes resulting from, among other things, weather and energy efficiency. This previous revenue recognition method resulted in more revenues during the third quarter and less revenues during the other quarters of each year. Beginning in

2017, in connection with the decoupling provisions of the FEJA, Ameren Illinois changed its method used to recognize interim period revenue. Ameren Illinois now recognizes revenue consistent with the timing of actual incurred electric distribution recoverable costs and recognizes revenue associated with the expected return on its rate base ratably over the year. Ameren Illinois recognized $75 million and $13 million of electric distribution revenue to reflect the difference between the estimate of its revenue requirement and the revenue requirement reflected in customer rates for the ~~six months ended June 30,~~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 ~~2016, respectively.~~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 ~~September~~ 2016, the FERC issued a final order in the November 2013 complaint case, which lowered the allowed base return on common equity ~~for the 15-month period of November 2013 to February 2015~~ to 10.32%, or a 10.82% total allowed return on common equity with the inclusion of a 50 basis point incentive adder for participation in an RTO. The order required customer refunds, with interest, to be issued for that 15-month period. During the first six months of 2017, Ameren and Ameren Illinois refunded $21 million and $17 million, respectively, related to the November 2013 complaint case. In addition, the 10.82% allowed return on common equity has been reflected in ratesRTO, effective since September 2016. The 10.82% allowed return on common equity ~~will likely~~may be replaced prospectively after the FERC issues a final order in the February 2015 complaint case, discussed below.

AsSince 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, which, if~~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 and~~RTO. It would also require customer refunds, with interest, for that 15-month period. ~~The timing~~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 issuance of the final order in the February 2015 complaint case is uncertain for two reasons. First, while the FERC reestablished a quorum of three commissioners in August 2017, they are under no deadline to issue a final order. Second, incurrent 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, ~~2017,~~2018, Ameren and Ameren Illinois had recorded current regulatory liabilities of ~~$41~~$43 million and ~~$24~~$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 ~~intercompany~~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, ~~2017~~2018, but were used to support commercial paper issuances and to issue letters of credit. Based on commercial paper outstanding, ~~as well as~~ letters of credit issued under the Credit Agreements, and cash on hand, the aggregate ~~amount of~~ credit capacity available under the Credit Agreements to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, at June 30, ~~2017~~2018, was $~~1.2~~1.6 billion. The Ameren Companies were in compliance with the covenants in their ~~credit agreements~~Credit Agreements as of June 30, ~~2017.~~2018. As of June 30, ~~2017,~~2018, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the provisions of the Credit Agreements, were ~~53%~~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, ~~2017,~~2018, and December 31, ~~2016:~~2017:


	2017		2016		2018		2017
Ameren (parent)	$	673	$	507	$	506	$	383
Ameren Missouri	60		—		—		39
Ameren Illinois	159		51		—		62
Ameren Consolidated	$	892	$	558	$	506	$	484

The following table summarizes the borrowing activity and relevant interest rates under ~~Ameren’s~~Ameren (parent),’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs for the six months ended June 30, ~~2017~~2018 and ~~2016:~~2017:


	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated			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	$	736		$	6		$	66		$	808
Average daily commercial paper outstanding at par value													$	736		$	6		$	66		$	808
Weighted-average interest rate	1.19		%	1.10		%	1.14		%	1.19		%	1.19		%	1.10		%	1.14		%	1.19		%
Peak commercial paper during period^(a)	$	841		$	60		$	163		$	948
Peak commercial paper during period at par value^(a)													$	841		$	60		$	163		$	948
Peak interest rate	1.50		%	1.41		%	1.50		%	1.50		%	1.50		%	1.41		%	1.50		%	1.50		%
2016
Average daily commercial paper outstanding	$	402		$	117		$	12		$	531
Weighted-average interest rate	0.82		%	0.74		%	0.79		%	0.80		%
Peak commercial paper during period^(a)	$	549		$	208		$	177		$	839
Peak interest rate	0.95		%	0.85		%	0.85		%	0.95		%


(a)	The timing of peak outstanding commercial paper issuances varies by company. Therefore, the sum of individual company peak ~~commercial paper issuances presented by company does~~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 ~~borrowing~~borrowings under the ~~utility~~ money pool for the three and six months ended June 30, ~~2017,~~2018, was ~~1.27%~~2.17% and ~~1.14%~~2.04%, respectively ~~(2016~~(2017 – ~~0.60%~~1.27% and ~~0.54%~~1.14%, respectively). See Note 8 – ~~Related Party~~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, ~~2017~~2018 and ~~2016~~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 ~~June 2017,~~April 2018, Ameren Missouri issued ~~$400~~$425 million ~~principal amount~~ of ~~2.95% senior secured notes~~4.00% first mortgage bonds due ~~June 2027,~~April 2048, with interest payable semiannually on ~~June~~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 ~~December~~November 15 of each year, beginning ~~December~~November 15, ~~2017.~~2018. Ameren ~~Missouri~~Illinois received proceeds of ~~$396~~$427 million, which were used ~~in conjunction with other available funds,~~ to repay ~~at maturity~~outstanding short-term debt, including short-term debt that Ameren Illinois incurred in ~~June 2017 $425~~connection with the repayment of $144 million ~~principal amount~~ of ~~Ameren Missouri’s 6.40%~~its 6.25% senior secured ~~notes.~~

~~ATXI~~

~~In June 2017, pursuant to a note purchase agreement, ATXI agreed to issue $450 million principal amount of 3.43% senior unsecured~~ notes due 2050 through a private placement offering exempt from registration under the Securities Act of 1933, as amended. ATXI issued $150 million principal amount of the notes in June 2017 and has agreed to issue the remaining $300 million principal amount of the notes in August 2017, subject to certain conditions. The proceeds of the notes, of which $149 million were received in June 2017, were, and will be used, by ATXI to repay existing short-term and long-term affiliate debt owed to Ameren (parent).

ATXI may prepay at any time not less than 5% of the principal amount of notes then outstanding at 100% of the principal amount plus a make-whole premium. In the event of a change of control, as defined in the agreement, each holder of notes may require ATXI to prepay the entire unpaid principal amount of the notes held by such holder at a price equal to 100% of the principal amount of such notes together with accrued and unpaid interest thereon, but without a premium. The following table presents the principal maturities schedule for the notes

~~(assuming the issuance of $450 million principal amount of notes):~~

Payment Date Principal Payment
August 2022 $ 49.5
August 2024 49.5
August 2027 49.5
August 2030 49.5
August 2032 49.5
August 2038 49.5
August 2043 76.5
August 2050 76.5
Total Principal Amount of Notes $ 450.0

~~The note purchase agreement includes financial covenants~~ that require ATXI to not permit at any time: (i) debt to exceed 70% of total capitalization or (ii) secured debt to exceed 10% of total assets. The note purchase agreement also contains restrictive covenants that, among other things, restrict the ability of ATXI to: (i) enter into transactions with affiliates; (ii) consolidate, merge, transfer or lease all or substantially all of its assets; and (iii) create liens.matured April 1, 2018.

Indenture Provisions and Other Covenants

Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions, but would restrict the companies’ ability to issue first mortgage bonds or preferred stock. See Note 5 – Long-Term Debt and Equity Financings under Part II, Item 8, in the Form 10-K for a description of our indenture provisions and other covenants, as well as restrictions on the payment of dividends. ~~See the discussion above for covenants related to ATXI’s note purchase agreement.~~ At June 30, ~~2017,~~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~~Off-balance-sheet Arrangements

At June 30, ~~2017,~~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~~(parent) guarantee arrangements on behalf of its subsidiaries. ~~None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.~~

NOTE 5 – OTHER INCOME, ~~AND EXPENSES~~NET

The following table presents the components of “Other Income, ~~and Expenses”~~Net” in the Ameren Companies’ statements of income for the three and six months ended June 30, ~~2017~~2018 and ~~2016~~2017:

Three Months Six Months
2017 2016 2017 2016
Ameren:^(a)

Miscellaneous income:
Allowance for equity funds used during construction $ 4
$ 5
$ 10
$ 13

Interest income on industrial development revenue bonds 6
6
13
13

Interest income 3
4
5
8

Other 1
1
1
2

Total miscellaneous income $ 14
$ 16
$ 29
$ 36

Miscellaneous expense:
Donations $ 2
$ 2
$ 7
$ 7

Other 3
4
7
6

Total miscellaneous expense $ 5
$ 6
$ 14
$ 13

Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction $ 4
$ 3
$ 9
$ 10

Interest income on industrial development revenue bonds 6
6
13
13

Other 1
—
1
1

Total miscellaneous income $ 11
$ 9
$ 23
$ 24

Three Months Six Months
2017 2016 2017 2016
Miscellaneous expense:
Donations $ 2
$ 1
$ 2
$ 2

Other —
1
2
2

Total miscellaneous expense $ 2
$ 2
$ 4
$ 4

Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction $ —
$ 2
$ 1
$ 3

Interest income 2
3
4
7

Other 1
1
1
1

Total miscellaneous income $ 3
$ 6
$ 6
$ 11

Miscellaneous expense:
Donations $ 1
$ 1
$ 5
$ 5

Other 1
2
3
3

Total miscellaneous expense $ 2
$ 3
$ 8
$ 8



	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 ~~power,~~ and ~~uranium,~~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 ~~and uranium~~ inventories that differ from the cost of those commodities in inventory; and

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

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

The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of June 30, ~~2017,~~2018, and December 31, ~~2016.~~2017. As of June 30, ~~2017,~~2018, these contracts extended through October ~~2019,~~2021, March 2023, and May 2032 ~~and March 2020~~ for fuel oils, natural gas, ~~power,~~ and ~~uranium,~~power, respectively.


	Quantity (in millions, except as indicated)						Quantity (in millions, except as indicated)
	2017			2016			2018			2017
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)^(a)	35	(b)	35	30	(b)	30	40	(b)	40	28	(b)	28
Natural gas (in mmbtu)	26	147	173	25	129	154	23	149	172	24	139	163
Power (in megawatthours)	1	9	10	1	9	10	2	8	10	3	9	12
Uranium (pounds in thousands)	445	(b)	445	345	(b)	345


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


(b)	Not applicable.

All contracts considered to be derivative instruments are required to be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 7 – Fair Value Measurements for a discussion of our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.

If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine whether the resulting gains or losses qualify for regulatory deferral. Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value recorded as regulatory assets or liabilities in the period in which the change occurs. We believe derivative losses and gains deferred as regulatory assets and liabilities are probable of recovery, or refund, through future rates charged to customers. Regulatory assets and liabilities are amortized to operating income as related losses and gains are reflected in rates

charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income. As of June 30, ~~2017,~~2018, and December 31, ~~2016,~~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, ~~2017,~~2018, and December 31, ~~2016:~~2017:


	Balance Sheet Location	Ameren Missouri			Ameren Illinois		Ameren			Balance Sheet Location	Ameren Missouri		Ameren Illinois		Ameren
2017
Fuel oils	Other current assets	$	1		$	—	$	1
Natural gas	Other current assets	—			1		1
	Other assets	—			1		1
Power	Other current assets	14			—		14
	Other assets	1			—		1
	Total assets ^(a)	$	16		$	2	$	18
Fuel oils	Other current liabilities	$	5		$	—	$	5
	Other deferred credits and liabilities	1			—		1
Natural gas	Other current liabilities	2			9		11
	Other deferred credits and liabilities	5			6		11
Power	Other current liabilities	1			13		14
	Other deferred credits and liabilities	—			179		179
Uranium	Other deferred credits and liabilities	—		^(b)	—		—		^(b)
	Total liabilities ^(c)	$	14		$	207	$	221
2016
2018										2018
Fuel oils	Other current assets	$	2		$	—	$	2		Other current assets	$	8	$	—	$	8
	Other assets	1			—		1			Other assets	5		—		5
Natural gas	Other current assets	1			11		12			Other current assets	—		1		1
	Other assets	1			2		3			Other assets	—		1		1
Power	Other current assets	9			—		9			Other current assets	7		—		7
	Total assets ^(a)	$	14		$	13	$	27		Total assets ^(a)	$	20	$	2	$	22
Fuel oils	Other current liabilities	$	5		$	—	$	5		Other deferred credits and liabilities	$	1	$	—	$	1
Natural gas	Other current liabilities	1			3		4			Other current liabilities	4		12		16
	Other deferred credits and liabilities	5			5		10			Other deferred credits and liabilities	3		13		16
Power	Other current liabilities	3			12		15			Other current liabilities	2		13		15
	Other deferred credits and liabilities	—			173		173			Other deferred credits and liabilities	—		177		177
Uranium	Other deferred credits and liabilities	4			—		4
	Total liabilities ^(c)	$	18		$	193	$	211		Total liabilities ^(b)	$	10	$	215	$	225
2017										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)	Beginning in 2017, as a result of rulebook amendments at the Chicago Mercantile Exchange, the fair value of uranium derivative liabilities are offset by certain settlement payments made to the exchange previously characterized as collateral and included within “Other assets” on Ameren’s and Ameren Missouri’s balance sheet.


~~(c)~~	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, ~~2017,~~2018, and December 31, ~~2016.~~

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, ~~2017,~~2018, if ~~counterparty groups~~all counterparties were to fail ~~completely~~ to perform on contracts, the Ameren Companies’ maximum exposure would have been immaterial with or without consideration of the application of master netting arrangements or similar agreements and collateral held.

Derivative Instruments with Credit ~~Risk-Related~~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, ~~2017~~,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, ~~2017~~,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)
2017
Ameren Missouri $ 65
$ 3
$ 59
Ameren Illinois 43
—
37
Ameren $ 108
$ 3
$ 96



	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. ~~All~~

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 ~~whose~~measured at fair value ~~measurement is based~~ on ~~significant unobservable inputs~~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 3.3 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, ~~2017~~2018, and December 31, ~~2016:~~2017:

Fair Value Weighted Average
Assets Liabilities Valuation Technique(s) Unobservable Input Range
Level 3 Derivative asset and liability – commodity contracts^(a):

2017
Fuel oils $ 1
$ (2 ) Option model
Volatilities(%)^(b)
26 – 36 27
Discounted cash flow
Counterparty credit risk(%)^(c)(d)
0.22 (e)

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

Escalation rate (%)^(b)(f)
0 – 1 0
Natural gas —
(2 ) Discounted cash flow
Nodal basis ($/mmbtu)^(b)
(0.80) – (0.10) (0.70)

Counterparty credit risk (%)^(c)(d)
0.45 – 6 0.82

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

Fair Value Weighted Average
Assets Liabilities Valuation Technique(s) Unobservable Input Range

Power^(g)
$ 15
$ (193 ) Discounted cash flow
Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(h)
25 – 42 29

Estimated auction price for FTRs ($/MW)^(b)
(730) – 1,398 284

Nodal basis ($/MWh)^(h)
(3) – 0 (2)

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)(i)
3 (e)
Contract price allocation
Estimated renewable energy credit costs ($/credit)^(b)
5 – 7 6
2016
Fuel oils $ 1
$ —
Option model
Volatilities (%)^(b)
24 – 66
28
Discounted cash flow
Counterparty credit risk (%)^(c)(d)
0.13 – 0.22
0.15

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

Escalation rate (%)^(b)(f)
(2) – 2
0
Natural gas 1
(1 ) Option model
Volatilities (%)^(b)
31 – 66
36

Nodal basis ($/mmbtu)^(b)
(0.40) – (0.10)
(0.20)
Discounted cash flow
Nodal basis ($/mmbtu)^(b)
(0.80) – 0
(0.50)

Counterparty credit risk (%)^(c)(d)
0.13 – 8
1

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

Power^(g)
9
(187 ) Discounted cash flow
Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(h)
26 – 44
29

Estimated auction price for FTRs ($/MW)^(b)
(71) – 5,270
125

Nodal basis ($/MWh)^(h)
(6) – 0
(2)

Ameren Illinois credit risk (%)^(c)(d)
0.38 (e)
Fundamental energy production model
Estimated future natural gas prices ($/mmbtu)^(b)
3 – 4
3

Escalation rate (%)^(b)(i)
5 (e)
Contract price allocation
Estimated renewable energy credit costs ($/credit)^(b)
5 – 7 6
Uranium —
(4 ) Option model
Volatilities (%)^(b)
24 (e)
Discounted cash flow
Average forward uranium pricing ($/pound)^(b)
22 – 24
22

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



		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Weighted Average
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)	~~Escalation rate applies to fuel oil prices 2019 and beyond.~~


~~(g)~~	Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through ~~2021~~2022 for June 30, ~~2017~~2018, and through ~~2020~~2021 for December 31, ~~2016.~~2017. Valuations beyond ~~2021~~2022 for June 30, ~~2017~~2018, and ~~2020~~2021 for December 31, ~~2016~~2017, use fundamentally modeled pricing by month for peak and off-peak demand.


~~(h)~~(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.


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

We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing, as well as any potential credit enhancements, into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. No gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri, or Ameren Illinois in the three and six months ended June 30, 2017 or 2016. At June 30, 2017, and December 31, 2016, the counterparty default risk valuation adjustment related to derivative contracts was immaterial for Ameren, Ameren Missouri, and Ameren Illinois.

The following table sets forth, by level within the fair value hierarchy, ~~our~~the carrying amount and fair value of financial assets and liabilities ~~measured~~disclosed, but not carried, at fair value ~~on a recurring basis~~ as of June 30, ~~2017~~:2018, and 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 $ —
$ —
$ 1
$ 1

Natural gas 1
1
—
2

Power —
—
15
15

Total derivative assets – commodity contracts
$ 1
$ 1
$ 16
$ 18

Nuclear decommissioning trust fund:
Cash and cash equivalents $ 2
$ —
$ —
$ 2

Equity securities:
U.S. large capitalization 426
—
—
426

Debt securities:
U.S. treasury and agency securities —
115
—
115

Corporate bonds —
83
—
83

Other —
23
—
23

Total nuclear decommissioning trust fund $ 428
$ 221
$ —
$ 649
^(b)
Total Ameren $ 429
$ 222
$ 16
$ 667

Ameren Missouri
Derivative assets – commodity contracts^(a):

Fuel oils $ —
$ —
$ 1
$ 1

Power —
—
15
15

Total derivative assets – commodity contracts
$ —
$ —
$ 16
$ 16

Nuclear decommissioning trust fund:
Cash and cash equivalents $ 2
$ —
$ —
$ 2

Equity securities:
U.S. large capitalization 426
—
—
426

Debt securities:
U.S. treasury and agency securities —
115
—
115

Corporate bonds —
83
—
83

Other —
23
—
23

Total nuclear decommissioning trust fund $ 428
$ 221
$ —
$ 649
^(b)
Total Ameren Missouri $ 428
$ 221
$ 16
$ 665

Ameren Illinois
Derivative assets – commodity contracts^(a):

Natural gas $ 1
$ 1
$ —
$ 2

Liabilities:
Ameren
Derivative liabilities – commodity contracts^(a):

Fuel oils $ 4
$ —
$ 2
$ 6

Natural gas —
20
2
22

Power —
—
193
193

Total Ameren $ 4
$ 20
$ 197
$ 221

Ameren Missouri
Derivative liabilities – commodity contracts^(a):

Fuel oils $ 4
$ —
$ 2
$ 6

Natural gas —
7
—
7

Power —
—
1
1

Total Ameren Missouri $ 4
$ 7
$ 3
$ 14

Ameren Illinois
Derivative liabilities – commodity contracts^(a):

Natural gas $ —
$ 13
$ 2
$ 15

Power —
—
192
192

Total Ameren Illinois $ —
$ 13
$ 194
$ 207



	June 30, 2018
	Carrying Amount			Fair Value
	Carrying Amount			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)

~~The derivative asset~~Ameren and ~~liability balances~~Ameren Missouri have investments in industrial revenue bonds, classified as held-to-maturity and recorded in “Other Assets,” that are ~~presented net~~equal to the capital lease obligation for CTs leased from the city of ~~counterparty credit considerations.~~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)

~~Balance excludes $2~~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 ~~receivables, payables,~~June 30, 2018. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $50 million, $20 million, and ~~accrued income, net.~~

~~The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of~~ ~~December 31, 2016~~:

Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)

Significant Other
Observable
Inputs
(Level 2)

Significant Other
Unobservable
Inputs
(Level 3)
Total
Assets:
Ameren
Derivative assets – commodity contracts^(a):

Fuel oils $ 2
$ —
$ 1
$ 3

Natural gas 2
12
1
15

Power —
—
9
9

Total derivative assets – commodity contracts
$ 4
$ 12
$ 11
$ 27

Nuclear decommissioning trust fund:
Cash and cash equivalents $ 1
$ —
$ —
$ 1

Equity securities:
U.S. large capitalization 408
—
—
408

Debt securities:
U.S. treasury and agency securities —
112
—
112

Corporate bonds —
67
—
67

Other —
17
—
17

Total nuclear decommissioning trust fund $ 409
$ 196
$ —
$ 605
^(b)
Total Ameren $ 413
$ 208
$ 11
$ 632

Ameren Missouri
Derivative assets – commodity contracts^(a):

Fuel oils $ 2
$ —
$ 1
$ 3

Natural gas —
1
1
2

Power —
—
9
9

Total derivative assets – commodity contracts
$ 2
$ 1
$ 11
$ 14

Nuclear decommissioning trust fund:
Cash and cash equivalents $ 1
$ —
$ —
$ 1

Equity securities:
U.S. large capitalization 408
—
—
408

Debt securities:
U.S. treasury and agency securities —
112
—
112

Corporate bonds —
67
—
67

Other —
17
—
17

Total nuclear decommissioning trust fund $ 409
$ 196
$ —
$ 605
^(b)
Total Ameren Missouri $ 411
$ 197
$ 11
$ 619

Ameren Illinois
Derivative assets – commodity contracts^(a):

Natural gas $ 2
$ 11
$ —
$ 13

Liabilities:
Ameren
Derivative liabilities – commodity contracts^(a):

Fuel oils $ 5
$ —
$ —
$ 5

Natural gas —
13
1
14

Power —
1
187
188

Uranium —
—
4
4

Total Ameren $ 5
$ 14
$ 192
$ 211

Ameren Missouri
Derivative liabilities – commodity contracts^(a):

Fuel oils $ 5
$ —
$ —
$ 5

Natural gas —
6
—
6

Power —
1
2
3

Uranium —
—
4
4

Total Ameren Missouri $ 5
$ 7
$ 6
$ 18

Ameren Illinois
Derivative liabilities – commodity contracts^(a):

Natural gas $ —
$ 7
$ 1
$ 8

Power —
—
185
185

Total Ameren Illinois $ —
$ 7
$ 186
$ 193


~~(a)~~	~~The derivative asset~~$24 million for Ameren, Ameren Missouri, and ~~liability balances are presented net~~Ameren Illinois, respectively, as of ~~counterparty credit considerations.~~December 31, 2017.


~~(b)~~(c)	~~Balance excludes $2 million~~The Level 3 fair value amount consists of ~~receivables, payables, and accrued income, net.~~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.

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, 2017 and 2016, the balances and changes in the fair value of Level 3 financial assets and liabilities associated with fuel oils, natural gas, and uranium were immaterial.

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

Net derivative commodity contracts

Ameren
Missouri

Ameren
Illinois
Ameren
For the three months ended June 30, 2017
Beginning balance at April 1, 2017 $ 4
$ (194 ) $ (190 )
Realized and unrealized gains (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 gains (losses) related to assets/liabilities held at June 30, 2017 $ —
$ (2 ) $ (2 )
For the three months ended June 30, 2016
Beginning balance at April 1, 2016 $ 6
$ (187 ) $ (181 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities (1 ) 14
13
Purchases 13
—
13
Settlements (4 ) 4
—
Ending balance at June 30, 2016 $ 14
$ (169 ) $ (155 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2016 $ —
$ 14
$ 14
For the six months ended June 30, 2017
Beginning balance at January 1, 2017 $ 7
$ (185 ) $ (178 )
Realized and unrealized gains (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 gains (losses) related to assets/liabilities held at June 30, 2017 $ —
$ (13 ) $ (13 )
For the six months ended June 30, 2016
Beginning balance at January 1, 2016 $ 16
$ (170 ) $ (154 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities (4 ) (7 ) (11 )
Purchases 13
—
13
Settlements (11 ) 8
(3 )
Ending balance at June 30, 2016 $ 14
$ (169 ) $ (155 )
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2016 $ —
$ (5 ) $ (5 )

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, 2017 and 2016, there were no material transfers between Level 1 and Level 2, Level 1 and Level 3, or Level 2 and Level 3 related to derivative commodity contracts.

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

~~The following table presents the carrying amounts and estimated fair values of our long-term debt, capital lease obligations and preferred stock at~~ ~~June 30, 2017, and~~ ~~December 31, 2016~~:

June 30, 2017 December 31, 2016

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value
Ameren:
Long-term debt and capital lease obligations (including current portion) $ 7,399
$ 7,942
$ 7,276
$ 7,772
Preferred stock^(a)
142
131
142
131
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion) $ 3,966
$ 4,310
$ 3,994
$ 4,304
Preferred stock 80
79
80
79
Ameren Illinois:
Long-term debt (including current portion) $ 2,589
$ 2,773
$ 2,588
$ 2,765
Preferred stock 62
52
62
52


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

NOTE 8 – ~~RELATED PARTY~~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 ~~affiliates~~Ameren’s subsidiaries are reported as ~~intercompany~~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~~related-party agreements and money pool arrangements, see Note 1413 – ~~Related Party~~Related-party Transactions and Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of the Form ~~10-K and the money pool arrangements discussed in Note 3 – Short-term Debt and Liquidity of this report.~~10-K.

Electric Power Supply Agreement

In April ~~2017,~~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 ~~2017,~~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, ~~85,600~~110,000 megawatthours at an average price of ~~$34~~$32 per megawatthour during the period of ~~March 1,~~June 2019 through ~~May 31,~~September 2020.

The following table presents the impact on Ameren Missouri and Ameren Illinois of ~~related party~~related-party transactions for the three and six months ended June 30, ~~2017~~2018 and ~~2016~~2017:


				Three Months				Six Months						Three Months				Six Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2017	$	6	$	(a)	$	17	$	(a)	Operating Revenues	2018	$	3	$	(a)	$	6	$	(a)
agreements with Ameren Illinois		2016		3		(a)		12		(a)		2017		6		(a)		17		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2017		6		1		13		2	Operating Revenues	2018		6		1		11		2
rent and facility services		2016		7		1		13		2		2017		6		1		13		2
Ameren Missouri and Ameren Illinois	Operating Revenues	2017		(b)		1		(b)		1	Operating Revenues	2018		(b)		(b)		(b)		(b)
miscellaneous support services		2016		(b)		(b)		(b)		(b)		2017		(b)		1		(b)		1
Total Operating Revenues		2017	$	12	$	2	$	30	$	3		2018	$	9	$	1	$	17	$	2
		2016		10		1		25		2		2017		12		2		30		3
Ameren Illinois power supply	Purchased Power	2017	$	(a)	$	6	$	(a)	$	17	Purchased Power	2018	$	(a)	$	3	$	(a)	$	6
agreements with Ameren Missouri		2016		(a)		3		(a)		12		2017		(a)		6		(a)		17
Ameren Illinois transmission	Purchased Power	2017		(a)		1		(a)		1	Purchased Power	2018		(a)		1		(a)		1
services with ATXI		2016		(a)		1		(a)		1		2017		(a)		1		(a)		1
Total Purchased Power		2017	$	(a)	$	7	$	(a)	$	18		2018	$	(a)	$	4	$	(a)	$	7
		2016		(a)		4		(a)		13		2017		(a)		7		(a)		18
Ameren Services support services	Other Operations and Maintenance	2017	$	34	$	34	$	69	$	66	Other Operations and Maintenance	2018	$	32	$	30	$	65	$	60
agreement		2016		32		30		66		61		2017		34		34		69		66
Money pool borrowings (advances)	Interest Charges/ Miscellaneous Income	2017	$	(b)	$	(b)	$	(b)	$	(b)	Interest Charges/ Other Income, Net	2018	$	(b)	$	(b)	$	(b)	$	(b)
		2016		(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 ~~our~~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 1413 – ~~Related Party~~Related-party Transactions, and Note 1514 – 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 ~~4 – Long-term Debt and Equity Financings, Note~~ 8 – ~~Related Party~~Related-party Transactions, and Note 10 – Callaway Energy Center of this report.

Other Obligations

~~In order to~~To supply a portion of the fuel requirements of Ameren Missouri’s energy centers, Ameren Missouri has entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. ~~Additionally,~~ Ameren Missouri and Ameren Illinois also have entered into various long-term commitments for purchased power and natural gas for distribution. ~~At June 30, 2017, total obligations related to commitments for coal, natural gas, nuclear~~The table below presents our estimated minimum fuel, purchased power, ~~methane gas,~~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 ~~Ameren, Ameren Missouri,~~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 were $3,655 million, $2,145 million, and $1,444 million, respectively. For additional information regarding our obligations and commitments at December 31, 2016, see Note 15 – Commitments and Contingencies under Part II, Item 8entered 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 ~~Form 10-K.~~subsequent planning year. The amounts above reflect Ameren Illinois’ commitment to acquire zero emission credits of approximately $57 million through May 2019.

In April ~~2017,~~2018, Ameren Illinois conducted a procurement ~~event,~~events, administered by the IPA, to purchase energy products through May ~~31, 2020.~~2021. In the April ~~2017~~2018 procurement event, Ameren Illinois contracted to purchase ~~4,249,800~~3,956,200 megawatthours of energy products for ~~$128~~$112 million from June ~~1, 2017,~~2018 through May ~~31, 2020.~~2021, which is reflected in the amounts above. See Note 8 – ~~Related Party~~Related-party Transactions for additional information regarding energy product agreements between Ameren Missouri and Ameren Illinois as a result of ~~this~~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 ~~diverse~~ environmental laws and regulations. These laws and regulations address emissions, discharges ~~into~~to water, water usage, impacts to air, land, and water, and chemical and waste handling. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures.

The EPA has promulgated environmental regulations that have a significant impact on the electric utility industry. Over time, compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants. As of December 31, ~~2016,~~2017, Ameren Missouri’s ~~fossil-fueled~~fossil fuel-fired energy centers represented ~~18%~~17% and ~~34%~~33% of Ameren’s and Ameren Missouri’s rate base, respectively. ~~Recent regulations impacting~~Regulations that apply to air emissions from the electric utility industry include the ~~revised~~ NSPS, the CSAPR, the MATS, and the ~~revised~~ National Ambient Air Quality Standards, which are subject to periodic review for certain pollutants. Collectively, these regulations cover a variety of pollutants, such as SO₂, particulate matter, NO_Xx,, mercury, toxic metals, and acid ~~gases. Regulation of~~gases, and CO₂ emissions from ~~existing~~new power ~~plants through the Clean Power Plan has been stayed by the United States Supreme Court, and the EPA is re-evaluating the legal and policy basis for the Clean Power Plan.~~plants. Water intake and discharges from power plants are regulated under the Clean Water ~~Act and potential~~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 resulting in significant capital expenditures. The EPA has initiated an administrative review of several regulations and rulemaking activities, including the Clean Power Plan and the effluent limitation guidelines, which could ultimately result in the revision of all or part of such rules.centers. The individual or combined effects of existing environmental regulations could result in significant capital expenditures, ~~and~~ increased operating costs, ~~for Ameren and Ameren Missouri. Compliance with existing environmental laws and regulations could be prohibitively expensive, result in~~or the closure or alteration of ~~the operation of~~operations at some of Ameren Missouri’s energy ~~centers, or require further capital investment.~~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~~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 ~~to $525 million in the aggregate~~ from ~~2017~~2018 through ~~2021~~2022 in order to comply with existing environmental regulations. ~~Ameren Missouri may be required to install additional~~Additional environmental controls beyond ~~2021.~~2022 could be required. This estimate of capital expenditures includes expenditures required ~~for~~by the CCR regulations, by the Clean Water Act ~~rules~~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. This estimate does not include the potential impacts of the Clean Power Plan~~ discussed below. The actual amount of capital expenditures required to comply with existing environmental regulations may vary substantially from the above estimate because of uncertainty as to whether the EPA will ~~substantively~~substantially revise regulatory obligations, ~~the precise~~exactly which compliance strategies ~~that~~ 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, ~~require significant reductions in~~including CSAPR, regulate emissions of SO₂and NO_x through ~~either~~ emission source reductions orand the use and retirement of emission allowances. The first phase of the CSAPR emission reduction requirements became effective in 2015. The second phase of emission reduction requirements, which were revised by the EPA in 2016, became effective in 2017; additional emission reduction requirements may apply in subsequent years. To achieve compliance with the CSAPR, Ameren Missouri burns ultra-low-sulfur coal, operates two scrubbers at its Sioux energy center, and optimizes other existing pollution control equipment. Ameren Missouri ~~did not make additional capital investments to comply with the 2017 CSAPR requirements. However, Ameren Missouri~~ expects to incur additional costs to lower its emissions at one or more of its energy centers to comply with the CSAPR in future years. These higher costs are expected to be recovered from customers through the FAC or higher base rates.

CO₂ Emissions Standards

In 2015, the EPA issued the Clean Power Plan, which ~~sets forth~~would have established CO₂emissions standards applicable to existing power plants. The ~~rule was stayed by the~~ United States Supreme Court stayed the rule in February 2016, pending ~~the outcome of~~ various legal challenges. In ~~April 2017,~~July 2018, the ~~EPA announced that it is reviewing~~Office of Management and ~~if appropriate, will initiate proceedings~~Budget received the EPA’s proposal to ~~suspend, revise, or rescind~~repeal and replace the Clean Power Plan. ~~The United States Court of Appeals for~~We expect that the ~~District of Columbia Circuit has stayed further action on the litigation that resulted from the Supreme Court’s February 2016 stay of the~~EPA's Clean Power Plan ~~pending~~replacement rule, including anticipated future emissions regulation, will be released and made publicly available later this year following the ~~EPA’s administrative~~Office of Management and Budget’s review.

~~In its current form, the Clean Power Plan would require significant reductions in CO~~₂ ~~emissions from power plants by 2030 including interim compliance periods commencing in 2022. The EPA has advised all states to discontinue implementation planning.~~ We cannot predict the outcome of ~~the~~ EPA’s ~~administrative review~~rulemaking or the outcome of legal challenges ~~nor the resulting impact on our results of operations, financial position, or liquidity.~~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 ~~will now proceed~~then proceeded to the second phase to determine the actions required to remedy the violations found in the liability ~~phase of the litigation.~~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 ~~2014,~~July 2018, the ~~EPA issued its final rule~~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~~plant’s cooling water system. All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to the cooling water intake structures rule. ~~Implementation of the~~The rule will ~~occur~~be implemented between 2018 and 2023, during the permit renewal process of each energy center’s water discharge ~~permit, which will occur between 2018 and 2023.~~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~~EPA’s 2015 rule prohibits effluent discharges of certain waste streams and imposes more stringent limitations on certain water discharges from

power plants. In ~~April~~September 2017, the EPA ~~announced~~published a rule that postponed the compliance dates by two years for the limitations applicable to two specific waste streams so that it ~~would review and reconsider~~could potentially revise those standards. Ameren Missouri is in the ~~effluent limitation guidelines and administratively stayed all compliance deadlines.~~

~~Both~~process of constructing wastewater treatment facilities at three of its energy centers. The cost to complete these facilities is included in the ~~intake and effluent rules, if implemented as enacted, could have an adverse effect on Ameren’s~~capital expenditures, discussed above, that Ameren and Ameren ~~Missouri’s results of operations, financial position, and liquidity should such implementation require extensive modifications~~Missouri estimate they will need to ~~the cooling water systems and water discharge systems at Ameren Missouri’s energy centers, and if such investments are not recovered on a timely basis~~make in ~~electric rates charged~~order to ~~Ameren Missouri’s customers.~~comply with existing environmental regulations.

~~Ash~~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~~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’s~~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 ~~2024.~~2023. The recent EPA revisions do not affect Ameren ~~Missouri's~~Missouri’s plan. Ameren Missouri estimates it will need to make capital ~~expenditure~~expenditures of $300 million to $350 million from 2018 through 2022 to implement its CCR management compliance plan, which includes ~~the cost~~installation of ~~constructing landfills as part of its environmental compliance plan.~~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, ~~2017,~~2018, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois, the majority of which ~~are in various stages of investigation, evaluation, remediation,~~have been investigated, remediated, and ~~closure.~~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 ~~associated with its former MGP sites~~ from its electric and natural gas utility customers through environmental ~~adjustment rate~~cost riders. Costs are subject to annual prudence review by the ICC. As of June 30, ~~2017,~~2018, Ameren Illinois estimated the obligation related to these former MGP sites at ~~$188~~$165 million to ~~$256~~$236 million. Ameren and Ameren Illinois recorded a liability of ~~$188~~$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, ~~the degree to which groundwater is encountered,~~technical feasibility of certain remediation measures, regulatory changes, ~~local ordinances,~~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. From about 1926 until 1976, Ameren Missouri operated an energy center adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property at Sauget Area 2 that was once used by others as a landfill.

In 2013, the EPA issued its record of decision for Sauget Area 2 approving the investigation and the remediation actions recommended by the potentially responsible parties. ~~Further negotiation among~~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 ~~parties will determine how~~party for Sauget Area 2, which limits Ameren Missouri’s cleanup obligation to ~~fund~~ the ~~implementation of~~site it owns. Remediation efforts at the ~~EPA-approved remedies.~~site are expected to occur in 2019. As of June 30, ~~2017,~~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.

~~Ameren Missouri Municipal Taxes~~

The cities of Creve Coeur and Winchester, Missouri, on behalf of themselves and other municipalities in Ameren Missouri’s service area, filed a class action lawsuit in 2011 against Ameren Missouri in the Circuit Court of St. Louis County, Missouri. The lawsuit alleges that Ameren Missouri failed to pay gross receipts taxes or license fees on certain revenues, including revenues from wholesale power and interchange sales. Ameren and Ameren Missouri recorded immaterial liabilities on their respective balance sheets as of June 30, 2017, and December 31, 2016, representing their estimate of the probable loss due as a result of this lawsuit. Ameren and Ameren Missouri believe there is a remote possibility that a liability relating to this lawsuit could be material to Ameren's and Ameren Missouri’s results of operations, financial position,

and liquidity. Ameren Missouri believes its defenses are meritorious and is defending itself vigorously. However, there can be no assurances that Ameren Missouri will be successful in its efforts. A 2018 trial has been set, and an order is expected later that year.

NOTE 10 – CALLAWAY ENERGY CENTER

Spent Nuclear Fuel

Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. The NWPA established the fee ~~that~~paid by Ameren Missouri and other utilities that own and operate those energy centers ~~pay~~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 ~~May~~ 2014. ~~The DOE's delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway energy center is not expected to adversely affect the continued operations of the energy center.~~

As a result of the DOE's failure to fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners sued the DOE to recover costs incurred for ongoing storage of their spent fuel. ~~The~~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, ~~2017~~2018 and ~~2016,~~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 ~~utility~~ rates charged to customers provide for the recovery of the Callaway energy ~~center's~~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~~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 ~~April 2016,~~January 2018, the MoPSC approved no change in ~~the annual~~electric rates for decommissioning costs ~~used to establish electric rates.~~based on Ameren Missouri’s updated cost study and funding analysis.

The fair value of the trust fund for Ameren ~~Missouri's~~Missouri’s Callaway energy center is reported as ~~"Nuclear~~“Nuclear decommissioning trust ~~fund"~~fund” in ~~Ameren's~~Ameren’s and Ameren ~~Missouri's~~Missouri’s balance sheets. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory liability. If the assumed return on trust assets is not earned, Ameren Missouri believes that it is probable that any such earnings deficiency will be recovered in rates.

~~Supplier of Fuel Assemblies~~

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

Insurance

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center atas of June 30, ~~2017.~~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 ~~2017.~~2018.


Type and Source of Coverage	Maximum Coverages			Maximum Assessments for Single Incidents			Maximum Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	450		$	—		$	450		$	—
Pool participation	12,986		^(a)	127		^(b)	12,604		^(a)	127		^(b)
	$	13,436	^(c)	$	127		$	13,054	^(c)	$	127
Property damage:
NEIL and EMANI	$	3,200	^(d)	$	29	^(e)	$	3,200	^(d)	$	27	^(e)
Replacement power:
NEIL	$	490	^(f)	$	7	^(e)	$	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.

The following table presents the components of the net periodic benefit cost ~~(benefit)~~(income), prior to capitalization, incurred for Ameren’s pension and postretirement benefit plans for the three and six months ended June 30, ~~2017~~2018 and ~~2016~~:2017:


	Pension Benefits												Postretirement Benefits												Pension Benefits												Postretirement Benefits
	Three Months						Six Months						Three Months						Six Months						Three Months						Six Months						Three Months						Six Months
	2017			2016			2017			2016			2017			2016			2017			2016			2018			2017			2018			2017			2018			2017			2018			2017
Service cost(a)	$	23		$	20		$	46		$	40		$	5		$	5		$	10		$	10		$	25		$	23		$	50		$	46		$	5		$	5		$	10		$	10
Non-service cost components:
Interest cost	45			45			90			92			11			12			23			24			42			45			84			90			9			11			20			23
Expected return on plan assets	(65		)	(63		)	(131		)	(126		)	(18		)	(18		)	(37		)	(36		)	(69		)	(65		)	(138		)	(131		)	(19		)	(18		)	(38		)	(37		)
Amortization of:
Prior service benefit	—			—			—			—			(1		)	(1		)	(2		)	(2		)	—			—			—			—			(1		)	(1		)	(2		)	(2		)
Actuarial loss (gain)	13			7			27			16			(1		)	(2		)	(3		)	(5		)	18			13			34			27			(3		)	(1		)	(3		)	(3		)
Net periodic benefit cost (benefit)	$	16		$	9		$	32		$	22		$	(4	)	$	(4	)	$	(9	)	$	(9	)
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 ~~costs~~ and ~~the~~other postretirement benefit costs ~~(benefit)~~(income) incurred for the three and six months ended June 30, ~~2017~~2018 and ~~2016~~:2017:


	Pension Benefits										Postretirement Benefits												Pension Benefits								Postretirement Benefits
	Three Months					Six Months					Three Months						Six Months						Three Months				Six Months				Three Months						Six Months
	2017		2016			2017		2016			2017			2016			2017			2016			2018		2017		2018		2017		2018			2017			2018			2017
Ameren Missouri^(a)	$	6	$	5		$	12	$	13		$	(1	)	$	(1	)	$	(2	)	$	(2	)	$	6	$	6	$	11	$	12	$	—		$	(1	)	$	—		$	(2	)
Ameren Illinois	10		6			20		11			(3		)	(3		)	(7		)	(7		)	10		10		19		20		(9		)	(3		)	(13		)	(7		)
Other	—		(2		)	—		(2		)	—			—			—			—
Ameren^(a)(b)	$	16	$	9		$	32	$	22		$	(4	)	$	(4	)	$	(9	)	$	(9	)
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.


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

NOTE 12 – SEGMENT INFORMATION

Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. Ameren Illinois Natural Gas consists of the natural gas business of Ameren Illinois. Ameren Transmission is primarily ~~composed of~~comprises the aggregated electric transmission businesses of Ameren Illinois and ATXI. The category called Other primarily includes Ameren ~~parent company~~(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 toat 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.~~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 atin Ameren ~~Transmission~~Transmission’s and Ameren Illinois ~~Transmission.~~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, ~~2017~~2018 and ~~2016~~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		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	$	923	$	387	$	134	$	92		$	2		$	—		$	1,538	$	922	$	387	$	134	$	92		$	2		$	—		$	1,537
Intersegment revenues	12		2		—		13		^(a)	—			(27		)	—		12		2		—		13			—			(27		)	—
Net income attributable to Ameren common shareholders	120		33		5		34		^(b)	1			—			193		120		33		5		34		^(a)	1			—			193
Capital expenditures	159		122		58		156			1			(2		)	494		159		122		58		156			1			(2		)	494
2016
Six Months
2018
External revenues	$	857	$	357	$	131	$	81		$	1		$	—		$	1,427	$	1,730	$	785	$	453	$	180		$	—		$	—		$	3,148
Intersegment revenues	10		1		—		11		^(a)	—			(22		)	—		17		2		—		27			—			(46		)	—
Net income attributable to Ameren common shareholders	92		18		7		32		^(b)	(2		)	—			147		206		66		49		73		^(a)	(4		)	—			390
Capital expenditures	175		119		45		164			1			—			504		454		254		126		275			5			(2		)	1,112
Six Months
2017
External revenues	$	1,695	$	771	$	398	$	188		$	—		$	—		$	3,052	$	1,695	$	771	$	398	$	188		$	—		$	—		$	3,052
Intersegment revenues	30		3		—		19		^(a)	—			(52		)	—		30		3		—		19			—			(52		)	—
Net income attributable to Ameren common shareholders	125		63		38		68		^(b)	1			—			295		125		63		38		68		^(a)	1			—			295
Capital expenditures	355		242		109		290			5			(3		)	998		355		242		109		290			5			(3		)	998
2016
External revenues	$	1,583	$	708	$	416	$	153		$	1		$	—		$	2,861
Intersegment revenues	25		2		—		22		^(a)	—			(49		)	—
Net income attributable to Ameren common shareholders	106		29		42		59		^(b)	16			—			252
Capital expenditures	353		236		80		328			3			—			1,000


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


~~(b)~~	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			Consolidated		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	$	389	$	134	$	53	$	—		$	576
Intersegment revenues	—		—		12		^(a)	(12		)	—		—		—		12		(12		)	—
Net income available to common shareholder	33		5		19			—			57		33		5		19		—			57
Capital expenditures	122		58		77			—			257		122		58		77		—			257
2016
Six Months
2018
External revenues	$	358	$	131	$	53		$	—		$	542	$	787	$	453	$	98	$	—		$	1,338
Intersegment revenues	—		—		10		^(a)	(10		)	—		—		—		26		(26		)	—
Net income available to common shareholder	18		7		20			—			45		66		49		42		—			157
Capital expenditures	119		45		67			—			231		254		126		222		—			602
Six Months
2017
External revenues	$	774	$	398	$	107		$	—		$	1,279	$	774	$	398	$	107	$	—		$	1,279
Intersegment revenues	—		—		18		^(a)	(18		)	—		—		—		18		(18		)	—
Net income available to common shareholder	63		38		35			—			136		63		38		35		—			136
Capital expenditures	242		109		133			—			484		242		109		133		—			484
2016
External revenues	$	710	$	416	$	93		$	—		$	1,219
Intersegment revenues	—		—		21		^(a)	(21		)	—
Net income available to common shareholder	29		42		33			—			104
Capital expenditures	236		80		126			—			442

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)

~~Ameren Illinois Transmission earns~~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 ~~transmission service provided to Ameren Illinois Electric Distribution.~~January 1, 2018, through June 30, 2018. See ~~discussion of transactions above.~~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

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

In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per ~~diluted~~ share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per ~~diluted~~ 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 ~~$193~~$239 million in the three months ended June 30, ~~2017,~~2018, compared with ~~$147~~$193 million in the year-ago period. Net income attributable to Ameren common shareholders was ~~$295~~$390 million in the six months ended June 30, ~~2017,~~2018, compared with ~~$252~~$295 million in the year-ago period. Net income ~~was favorably affected~~ in the three and six months ended June 30, ~~2017,~~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 ~~of tracked~~ expenses at Ameren Missouri, pursuant to the MoPSC’s March 2017 electric rate order as well as by a change in the method used to recognize interim period revenue related to Ameren Illinois Electric Distribution’s revenue requirement reconciliation in connection with the decoupling provisions of the FEJA.order. Earnings were also favorably affected by ~~the absence~~increased infrastructure investments in ~~2017 of costs associated with~~ the ~~Callaway energy center’s scheduled refueling and maintenance outage in 2016 and increased~~ Ameren Transmission, ~~and~~ Ameren Illinois Electric Distribution, ~~investment, reflecting Ameren’s strategy to allocate incremental capital to those businesses. Mild temperatures in 2017~~ and ~~increased depreciation and amortization expenses~~

Ameren Illinois Natural Gas segments. Net income was unfavorably affected ~~net income~~ in the three and six months ended June 30, ~~2017,~~2018, compared to the year-ago ~~periods. Additionally, in the six months ended June 30, 2017, compared with the year-ago~~ period, ~~earnings were affected~~ by ~~an increase in the effective tax rate~~increased other operation and maintenance expenses and by increased depreciation and amortization expenses, both primarily ~~due to a decrease in the income tax benefit recorded~~ at Ameren ~~(parent) related to share-based compensation.~~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 ~~2017,~~2018, Ameren ~~continued to allocate significant amounts of capital to those businesses that are supported by constructive regulatory frameworks, investing more than $640~~invested $655 million of capital expenditures in its FERC rate-regulated electric transmission and Illinois electric and natural gas distribution businesses.

In ~~March 2017,~~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, ~~issued~~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 ~~order approving~~annual basis without a ~~unanimous stipulation and agreement in Ameren Missouri’s July 2016~~traditional regulatory rate review. The ~~electric rate order resulted~~RESRAM is designed to mitigate the impacts of regulatory lag for investments in ~~a $92 million increase in Ameren Missouri’s revenue requirement, a $54 million decrease in the base level~~wind generation and other renewables by providing more timely recovery of ~~net energy~~ costs and would provide Ameren Missouri a ~~$26 million reduction in the base level of certain tracked expenses, compared~~greater opportunity to earn its allowed return on investment. Ameren Missouri anticipates a decision by January 2019 related to the ~~amounts in~~certificate of convenience and necessity and proposed RESRAM. Further, Ameren Missouri is also pursuing the ~~MoPSC’s April 2015 rate order. The new rates and base level~~acquisition of ~~expenses became effective on April 1, 2017.~~

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 ~~approximately $350~~$380 million in electric distribution and natural gas infrastructure projects in the first six months of ~~2017.~~2018. In April ~~2017,~~2018, Ameren Illinois filed ~~with the ICC~~ its annual electric distribution service formula rate update to establish the revenue requirement to be used for ~~2018 rates.~~2019 rates with the ICC. In ~~June 2017,~~July 2018, the ICC staff submitted its calculation of the revenue requirement ~~which~~included in Ameren ~~Illinois supported in its revised July 2017~~Illinois’ update filing, ~~and recommended a decrease~~recommending an amount comparable to ~~the electric distribution service revenue requirement.~~Ameren Illinois’ filing. Pending ICC approval, this update filing will result in a ~~$17~~$72 million ~~decrease~~increase in Ameren Illinois’ electric distribution service ~~revenue requirement~~rates beginning in January ~~2018.~~2019. This update reflects an increase to the annual formula rate based on ~~2016~~2017 actual costs and expected net plant additions for ~~2017, as well as~~2018 and an increase to include the ~~2016~~2017 revenue requirement reconciliation adjustment. ~~The increases in the update filing are more than offset by~~It also includes a decrease for the conclusion of the ~~2015~~2016 revenue requirement reconciliation adjustment, which will be fully collected from customers in ~~2017.~~2018. An ICC decision on the revenue requirement to be used for ~~2018~~2019 rates is expected by December ~~2017.~~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 ~~2017,~~2018, Ameren Transmission invested ~~$290~~$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 ~~and Spoon River projects~~project are continuing on schedule, and ~~are~~the last section of this project is expected to be completed by ~~2019 and 2018, respectively.~~the end of 2019. Related to ~~its~~ATXI’s Mark Twain project, in April 2017, ATXI reached agreements in principle with a cooperative electric company in northeast Missouri and with Ameren Missouri to locate the majority of that project on existing transmission line corridors, resulting in a proposed alternative project route. ATXI isconstruction activities began in the ~~process of finalizing the proposed alternative project route and plans to request assents for road crossings from the five affected counties in the third~~second quarter of ~~2017. If all five county commissions provide assents for the proposed alternative project route, ATXI will then seek MoPSC approval.~~

In June 2017, pursuant to a note purchase agreement, ATXI agreed to issue $450 million principal amount of 3.43% senior unsecured notes due 2050 through a private placement offering. ATXI issued $150 million principal amount2018 with completion of the ~~notes in June 2017 and has agreed to issue $300 million principal amount~~project expected by the end of ~~the notes in August 2017, subject to certain conditions. The proceeds of the notes were and will be used by ATXI to repay existing short-term and long-term affiliate debt owed to Ameren (parent).~~2019.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Economic conditions, ~~energy efficiency~~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, ~~with regulatory~~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'~~Illinois’ electric distribution service business, and a FAC for Ameren ~~Missouri's~~Missouri’s electric utility business.

Ameren Missouri’s FAC cost recovery mechanism allows it to recover or refund, through customer rates, 95% of ~~changes~~the variance in net energy costs ~~greater or less than~~from the amount set in base rates without a traditional regulatory rate ~~proceeding,~~review, subject to MoPSC prudence reviews, with the remaining 5% of changes retained by Ameren Missouri. Net energy costs, as defined in the FAC, include fuel and purchased power costs net of off-system sales. Ameren Missouri accrues net energy costs that exceed the amount set in base rates (FAC under-recovery) as a regulatory asset. Net recovery of these costs through customer rates does not affect Ameren ~~Missouri's~~Missouri’s electric margins, as any change in revenue is offset by a corresponding change in fuel ~~expense to reduce~~expense. In addition, Ameren Missouri’s MEEIA customer energy-efficiency program costs, the ~~previously recognized FAC~~throughput disincentive, and any performance incentive are recoverable through the MEEIA cost recovery mechanism without a traditional regulatory ~~asset. See the definition of margin in the Electric and Natural Gas Margins section below.~~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.~~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'~~Illinois’ electric or natural gas margins, as any change in costs is offset by a corresponding change in revenues.

~~Under~~ Ameren Illinois ~~law, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable~~employs other cost recovery mechanisms for natural gas customer energy-efficiency program costs and ~~allowed return on equity. These recoverable electric distribution~~certain environmental costs, ~~include other operations~~as well as bad debt expenses and ~~maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes. These recoverable~~ costs doof certain asbestos-related claims not ~~include those costs~~ recovered ~~through separate cost recovery mechanisms. A portion of the electric distribution costs included~~ in ~~those income statement line items are not recoverable based on the IEIMA’s formula rate framework. If a given year's revenue requirement is~~base rates.

greater than the revenue requirement reflected in that year's customer rates, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional amounts from customers within two years. If a given year's revenue requirement is less than the revenue requirement reflected in that year's customer rates, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within two years.

Ameren Illinois’ electric distribution service revenue requirement is, in part, based on year-end rate base and capital structure, which currently includes 50% common equity. It also includes a formula for the return on equity, which is equal to the average of the monthly yields of 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois' annual return on equity for its electric distribution business is directly correlated to yields on United States Treasury bonds. Beginning in 2017, the FEJA also provides that Ameren Illinois recovers, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes.

~~The provisions of FERC's~~FERC’s electric transmission formula rate framework ~~provide~~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. These recoverable transmission costs are included in other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes. A portion of the transmission costs included in those income statement line items are not recoverable based on the FERC formula rate framework. Ameren Illinois and ATXI use a company-specific, forward-looking ~~rate~~ formula ratemaking framework in setting their transmission rates. These rates are updated each January with forecasted information. If a given ~~year's~~year’s revenue requirement varies from the amount collected from customers, an adjustment is ~~greater than the revenue requirement reflected in that year's customer rates, an increase~~made to electric operating revenues with an offset to a regulatory asset ~~is recorded~~or liability to reflect ~~the expected recovery of those additional amounts~~that year’s actual revenue requirement. The regulatory balance is collected from, or

refunded to, customers within two years. If a given year's revenue requirement is less than the revenue requirement reflected in that year's customer rates, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within two years.

The total return on equity currently allowed for Ameren Illinois’ and ATXI’s electric transmission service businesses is 10.82% and is subject to a FERC complaint case. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information.

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, ~~2017~~2018 and ~~2016:~~

2017:


	Three Months				Six Months				Three Months				Six Months
	2017		2016		2017		2016		2018		2017		2018		2017
Net income attributable to Ameren common shareholders	$	193	$	147	$	295	$	252	$	239	$	193	$	390	$	295
Earnings per common share – basic and diluted	0.79		0.61		1.21		1.04
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, ~~2017,~~2018, compared with the year-ago period. The increase was ~~principally~~primarily due to net income increases of ~~$28~~$48 million, ~~$15~~$2 million, and $2 million at Ameren Missouri, Ameren Illinois ~~Electric Distribution, and Ameren Transmission, respectively.~~

Net income attributable to Ameren common shareholders increased $43 million, or 17 cents per diluted share, in the six months ended June 30, 2017, compared with the year-ago period. The increase was due to net income increases of $34 million, $19 million, and $9 million at Ameren Illinois Electric Distribution, Ameren Missouri,Natural Gas, and Ameren Transmission, respectively. The increase was partially offset by a ~~decrease in~~ net ~~income~~loss of ~~$15~~$5 million for activity not reported as part of a segment, primarily at Ameren (parent), ~~and a decrease in~~compared with net income of $4$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.~~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, ~~2017,~~2018, compared to the year-ago periods (except where a specific period is referenced), by:

~~a change~~increased demand in ~~the method used~~2018 at Ameren Missouri, primarily due to ~~recognize Ameren Illinois Electric Distribution’s interim period revenue~~colder winter and warmer early summer temperatures experienced in ~~connection with the decoupling provisions of the FEJA as discussed in Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report (4~~2018 (estimated at 24 cents per share and 1232 cents per share, respectively);

~~an increase in~~increased base rates and lower base level of expenses at Ameren Missouri, pursuant to the MoPSC’s March 2017 electric rate order ~~as discussed in Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report (11~~(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);

the absence in 2017 of costs associated with the Callaway energy center’s scheduled refueling and maintenance outage in the second quarter of 2016. The 2017 refueling and maintenance outage is scheduled for the fall (7decreased 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 82 cents per share, respectively);

increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base ~~(2 cents per share and 4 cents per share, respectively); and~~

~~increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional rate base~~ investment ~~as well as a higher recognized return on equity~~ (1 cent per share and 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, ~~2017,~~2018, compared to the year-ago periods (except where a specific period is referenced), by:

~~decreased demand~~increased other operation and maintenance expenses not subject to riders or regulatory tracking mechanisms, primarily at Ameren Missouri ~~due to milder winter and early summer temperatures in 2017 (estimated at 5~~(5 cents per share and 8 cents per share, respectively);

~~an increase in the effective tax rate~~decreased earnings at Ameren Missouri and Ameren Illinois Natural Gas, primarily due to ~~a decrease in~~timing differences between the recognition of revenue and income tax ~~benefit recorded at Ameren (parent) related to share- based compensation (5~~expense (3 cents per share ~~for the six months ended June 30, 2017)~~and 4 cents per share, respectively); ~~and~~

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 ~~as multiple projects were completed~~(2 cents per share and 4 cents per share, respectively); and

an increase in ~~2016~~weighted-average diluted shares outstanding (1 cent per share ~~and 3 cents per share, respectively)~~for both periods).

The cents per share information presented is based on the ~~average diluted~~weighted-average basic shares outstanding in the three and six months ended ~~June 30, 2016.~~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 ~~2016~~2018 statutory tax rate of ~~39%~~27%. For additional

details regarding the Ameren Companies’ results of operations, including explanations of Electric and Natural Gas Margins, Other Operations and Maintenance Expenses, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income, ~~and Expenses,~~Net, Interest Charges, and Income Taxes, see the major headings below.

Below is Ameren’s table of income statement components by segment for the three and six months ended June 30, ~~2017~~2018 and ~~2016:~~2017:


	Ameren Missouri			Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas			Ameren Transmission			Other / Intersegment Eliminations			Total			Ameren Missouri			Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas			Ameren Transmission			Other / Intersegment Eliminations			Total
Three Months 2017:
Electric margins	$	656		$	289		$	—		$	105		$	(5	)	$	1,045
Natural gas margins	17			—			98			—			(1		)	114
Other revenues	—			1			—			—			(1		)	—
Other operations and maintenance	(219		)	(142		)	(54		)	(15		)	8			(422		)
Depreciation and amortization	(132		)	(59		)	(15		)	(15		)	(1		)	(222		)
Taxes other than income taxes	(85		)	(18		)	(10		)	(2		)	(2		)	(117		)
Other income (expense)	9			1			—			—			(1		)	9
Interest charges	(53		)	(18		)	(9		)	(16		)	(3		)	(99		)
Income (taxes) benefit	(72		)	(21		)	(4		)	(23		)	6			(114		)
Net income (loss)	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
Three Months 2016:
Three Months 2018:
Electric margins	$	628		$	258		$	—		$	92		$	(5	)	$	973		$	704		$	269		$	—		$	103		$	(8	)	$	1,068
Natural gas margins	17			—			96			—			(1		)	112			17			—			99			—			—			116
Other operations and maintenance	(238		)	(137		)	(49		)	(15		)	4			(435		)	(241		)	(129		)	(54		)	(16		)	1			(439		)
Depreciation and amortization	(127		)	(58		)	(13		)	(10		)	(2		)	(210		)	(138		)	(65		)	(17		)	(19		)	1			(238		)
Taxes other than income taxes	(83		)	(18		)	(11		)	(1		)	(2		)	(115		)	(84		)	(21		)	(13		)	(3		)	(1		)	(122		)
Other income (expense)	7			3			—			—			—			10
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	(53		)	(19		)	(9		)	(13		)	(1		)	(95		)	(102		)	(37		)	(19		)	(37		)	(6		)	(201		)
Income (taxes) benefit	(58		)	(11		)	(6		)	(21		)	4			(92		)	(67		)	(19		)	(17		)	(27		)	14			(116		)
Net income (loss)	93			18			8			32			(3		)	148			208			67			50			73			(5		)	393
Noncontrolling interests – preferred stock dividends	(1		)	—			(1		)	—			1			(1		)	(2		)	(1		)	(1		)	—			1			(3		)
Net income (loss) attributable to Ameren common shareholders	$	92		$	18		$	7		$	32		$	(2	)	$	147		$	206		$	66		$	49		$	73		$	(4	)	$	390
Six Months 2017:
Electric margins	$	1,105		$	567		$	—		$	207		$	(14	)	$	1,865		$	1,104		$	568		$	—		$	207		$	(15	)	$	1,864
Natural gas margins	41			—			252			—			(1		)	292			41			—			252			—			(1		)	292
Other revenues	—			1			—			—			(1		)	—
Other operations and maintenance	(431		)	(273		)	(107		)	(31		)	15			(827		)	(443		)	(276		)	(109		)	(31		)	10			(849		)
Depreciation and amortization	(265		)	(118		)	(29		)	(29		)	(2		)	(443		)	(265		)	(118		)	(29		)	(29		)	(2		)	(443		)
Taxes other than income taxes	(160		)	(36		)	(31		)	(3		)	(5		)	(235		)	(160		)	(36		)	(31		)	(3		)	(5		)	(235		)
Other income (expense)	19			—			(2		)	—			(2		)	15
Interest charges	(107		)	(36		)	(19		)	(31		)	(5		)	(198		)
Income (taxes) benefit	(75		)	(41		)	(25		)	(45		)	15			(171		)
Net income (loss)	127			64			39			68			—			298
Noncontrolling interests – preferred dividends	(2		)	(1		)	(1		)	—			1			(3		)
Net income attributable to Ameren common shareholders	$	125		$	63		$	38		$	68		$	1		$	295
Six Months 2016:
Electric margins	$	1,077		$	495		$	—		$	175		$	(13	)	$	1,734
Natural gas margins	43			—			250			—			(1		)	292
Other operations and maintenance	(450		)	(267		)	(101		)	(30		)	13			(835		)
Depreciation and amortization	(254		)	(112		)	(27		)	(20		)	(4		)	(417		)
Taxes other than income taxes	(156		)	(34		)	(32		)	(2		)	(5		)	(229		)
Other income (expense)	20			3			(1		)	1			—			23
Other income (expense), net																			32			4			(1		)	—			3			38
Interest charges	(105		)	(37		)	(18		)	(26		)	(4		)	(190		)	(107		)	(37		)	(18		)	(31		)	(5		)	(198		)
Income (taxes) benefit	(67		)	(18		)	(28		)	(39		)	29			(123		)	(75		)	(41		)	(25		)	(45		)	15			(171		)
Net income	108			30			43			59			15			255			127			64			39			68			—			298
Noncontrolling interests – preferred dividends	(2		)	(1		)	(1		)	—			1			(3		)
Noncontrolling interests – preferred stock dividends																			(2		)	(1		)	(1		)	—			1			(3		)
Net income attributable to Ameren common shareholders	$	106		$	29		$	42		$	59		$	16		$	252		$	125		$	63		$	38		$	68		$	1		$	295

Below is Ameren Illinois' table of income statement components by segment for the three and six months ended June 30, ~~2017~~2018 and ~~2016:~~2017:


	Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas			Ameren Illinois Transmission			Total			Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas			Ameren Illinois Transmission			Total
Three Months 2017:
Three Months 2018:
Electric and natural gas margins	$	289		$	98		$	65		$	452		$	269		$	99		$	62		$	430
Other revenues	1			—			—			1
Other operations and maintenance	(142		)	(54		)	(14		)	(210		)	(129		)	(54		)	(13		)	(196		)
Depreciation and amortization	(59		)	(15		)	(11		)	(85		)	(65		)	(17		)	(12		)	(94		)
Taxes other than income taxes	(18		)	(10		)	—			(28		)	(21		)	(13		)	(1		)	(35		)
Other income	1			—			—			1
Other income, net													8			4			1			13
Interest charges	(18		)	(9		)	(9		)	(36		)	(19		)	(9		)	(9		)	(37		)
Income taxes	(21		)	(4		)	(12		)	(37		)	(10		)	(2		)	(6		)	(18		)
Net income	33			6			19			58			33			8			22			63
Preferred stock dividends	—			(1		)	—			(1		)	—			(1		)	—			(1		)
Net income attributable to common shareholder	$	33		$	5		$	19		$	57		$	33		$	7		$	22		$	62
Three Months 2016:
Three Months 2017:
Electric and natural gas margins	$	258		$	96		$	63		$	417		$	290		$	98		$	65		$	453
Other operations and maintenance	(137		)	(49		)	(14		)	(200		)	(143		)	(55		)	(14		)	(212		)
Depreciation and amortization	(58		)	(13		)	(9		)	(80		)	(59		)	(15		)	(11		)	(85		)
Taxes other than income taxes	(18		)	(11		)	(1		)	(30		)	(18		)	(10		)	—			(28		)
Other income	3			—			—			3
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	(19		)	(9		)	(7		)	(35		)	(37		)	(19		)	(18		)	(74		)
Income taxes	(11		)	(6		)	(12		)	(29		)	(19		)	(17		)	(14		)	(50		)
Net income	18			8			20			46			67			50			42			159
Preferred stock dividends	—			(1		)	—			(1		)	(1		)	(1		)	—			(2		)
Net income attributable to common shareholder	$	18		$	7		$	20		$	45		$	66		$	49		$	42		$	157
Six Months 2017:
Electric and natural gas margins	$	567		$	252		$	125		$	944		$	568		$	252		$	125		$	945
Other revenues	1			—			—			1
Other operations and maintenance	(273		)	(107		)	(27		)	(407		)	(276		)	(109		)	(27		)	(412		)
Depreciation and amortization	(118		)	(29		)	(21		)	(168		)	(118		)	(29		)	(21		)	(168		)
Taxes other than income taxes	(36		)	(31		)	(1		)	(68		)	(36		)	(31		)	(1		)	(68		)
Other income (expense)	—			(2		)	—			(2		)
Other income (expense), net													4			(1		)	—			3
Interest charges	(36		)	(19		)	(18		)	(73		)	(37		)	(18		)	(18		)	(73		)
Income taxes	(41		)	(25		)	(23		)	(89		)	(41		)	(25		)	(23		)	(89		)
Net income	64			39			35			138			64			39			35			138
Preferred stock dividends	(1		)	(1		)	—			(2		)	(1		)	(1		)	—			(2		)
Net income attributable to common shareholder	$	63		$	38		$	35		$	136		$	63		$	38		$	35		$	136
Six Months 2016:
Electric and natural gas margins	$	495		$	250		$	114		$	859
Other operations and maintenance	(267		)	(101		)	(26		)	(394		)
Depreciation and amortization	(112		)	(27		)	(18		)	(157		)
Taxes other than income taxes	(34		)	(32		)	(2		)	(68		)
Other income (expense)	3			(1		)	1			3
Interest charges	(37		)	(18		)	(15		)	(70		)
Income taxes	(18		)	(28		)	(21		)	(67		)
Net income	30			43			33			106
Preferred stock dividends	(1		)	(1		)	—			(2		)
Net income attributable to common shareholder	$	29		$	42		$	33		$	104

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, ~~2017,~~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			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)	$	(19	)	$	(4	)	$	—		$	—	$	—		$	(23	)	$	69		$	—		$	—		$	—		$	—		$	69
Base rates (estimate)^(c)	24			15			—			13		—			52			(37		)	(8		)	—			(2		)	—			(47		)
FEJA impact on IEIMA – timing of revenue recognition	—			15			—			—		—			15
Sales volume (excluding the effect of weather and the New Madrid Smelter)	(1		)	—			—			—		—			(1		)
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			(54		)	—			—			—			—			(54		)
Energy-efficiency program investments																		—			3			—			—			—			3
Other	2			4			—			—		(3		)	3			9			1			—			—			—			10
Cost recovery mechanisms – offset in fuel and purchased power:^(d)
Power supply costs	—			(5		)	—			—		—			(5		)
Transmission services recovery mechanism	—			4			—			—		—			4
Recovery of FAC under-recovery	1			—			—			—		—			1
Other cost recovery mechanisms:^(e)
Bad debt, energy efficiency programs, and remediation cost riders	—			1			—			—		—			1
MEEIA program costs	8			—			—			—		—			8
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	$	69		$	30		$	—		$	13	$	(3	)	$	109		$	18		$	(2	)	$	—		$	(2	)	$	—		$	14
Fuel and purchased power change:
Energy costs (excluding the effect of weather and the New Madrid Smelter)	$	(52	)	$	—		$	—		$	—	$	—		$	(52	)
New Madrid Smelter energy costs	(1		)	—			—			—		—			(1		)
Energy costs (excluding the effect of weather)																		$	49		$	—		$	—		$	—		$	—		$	49
Effect of weather (estimate)^(b)	3			1			—			—		—			4			(11		)	—			—			—			—			(11		)
Effect of lower net energy costs included in base rates	12			—			—			—		—			12
Transmission services charges	(2		)	—			—			—		—			(2		)
Other	—			(1		)	—			—		3			2			—			—			—			—			(2		)	(2		)
Cost recovery mechanisms – offset in electric revenue:^(d)
Power supply costs	—			5			—			—		—			5
Transmission services recovery mechanism	—			(4		)	—			—		—			(4		)
Recovery of FAC under-recovery	(1		)	—			—			—		—			(1		)
Cost recovery mechanisms – offset in electric revenue^(d)																		(6		)	(19		)	—			—			—			(25		)
Total fuel and purchased power change	$	(41	)	$	1		$	—		$	—	$	3		$	(37	)	$	32		$	(19	)	$	—		$	—		$	(2	)	$	11
Net change in electric margins	$	28		$	31		$	—		$	13	$	—		$	72		$	50		$	(21	)	$	—		$	(2	)	$	(2	)	$	25
Natural gas revenue change:
Effect of weather (estimate)^(b)	$	(1	)	$	—		$	—		$	—	$	—		$	(1	)	$	7		$	—		$	—		$	—		$	—		$	7
Base rates (estimate)																		—			—			(7		)	—			—			(7		)
QIP rider	—			—			3			—		—			3			—			—			6			—			—			6
Other	—			—			(1		)	—		—			(1		)	—			—			—			—			1			1
Purchased natural gas costs – offset in natural gas purchased for resale^(d)	—			—			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	$	(1	)	$	—		$	3		$	—	$	—		$	2		$	3		$	—		$	8		$	—		$	1		$	12
Natural gas purchased for resale change:
Effect of weather (estimate)^(b)	$	1		$	—		$	—		$	—	$	—		$	1		$	(7	)	$	—		$	—		$	—		$	—		$	(7	)
Purchased natural gas costs – offset in natural gas revenue^(d)	—			—			(1		)	—		—			(1		)
Cost recovery mechanisms – offset in natural gas revenue^(d)																		4			—			(7		)	—			—			(3		)
Total natural gas purchased for resale change	$	1		$	—		$	(1	)	$	—	$	—		$	—		$	(3	)	$	—		$	(7	)	$	—		$	—		$	(10	)
Net change in natural gas margins	$	—		$	—		$	2		$	—	$	—		$	2		$	—		$	—		$	1		$	—		$	1		$	2

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)
$ (39 ) $ 2
$ —
$ —
$ —
$ (37 )
Base rates (estimate)^(c)
24
21
—
32
—
77
FEJA impact on IEIMA – timing of revenue recognition

—
47
—
—
—
47
Sales volume (excluding the effect of weather and the New Madrid Smelter) (6 ) —
—
—
—
(6 )
New Madrid Smelter revenues (8 ) —
—
—
—
(8 )
Off-system sales 133
—
—
—
—
133
Other 10
—
—
—
(3 ) 7
Cost recovery mechanisms – offset in fuel and purchased power:^(d)

     Power supply costs —
(11 ) —
—
—
(11 )
     Transmission services recovery mechanism —
1
—
—
—
1
     Recovery of FAC under-recovery (10 ) —
—
—
—
(10 )
Other cost recovery mechanisms:^(e)

Bad debt, energy efficiency programs, and remediation cost riders —
3
—
—
—
3
     Gross receipts tax 1
—
—
—
—
1
     MEEIA program costs 16
—
—
—
—
16
Total electric revenue change $ 121
$ 63
$ —
$ 32
$ (3 ) $ 213
Fuel and purchased power change:
Energy costs (excluding the effect of weather and the New Madrid Smelter) $ (131 ) $ —
$ —
$ —
$ —
$ (131 )
New Madrid Smelter energy costs 7
—
—
—
—
7
Effect of weather (estimate)^(b)
9
(2 ) —
—
—
7
Effect of lower net energy costs included in base rates 12
—
—
—
—
12
Transmission service charges (2 ) —
—
—
—
(2 )
Other 2
1
—
—
2
5
Cost recovery mechanisms – offset in electric revenue:^(d)

      Power supply costs —
11
—
—
—
11
      Transmission services recovery mechanism —
(1 ) —
—
—
(1 )
      Recovery of FAC under-recovery 10
—
—
—
—
10
Total fuel and purchased power change $ (93 ) $ 9
$ —
$ —
$ 2
$ (82 )
Net change in electric margins $ 28
$ 72
$ —
$ 32
$ (1 ) $ 131
Natural gas revenue change:
Effect of weather (estimate)^(b)
$ (6 ) $ —
$ —
$ —
$ —
$ (6 )
QIP rider —
—
3
—
—
3
Other (1 ) —
(1 ) —
—
(2 )
Purchased natural gas costs – offset in natural gas purchased for resale^(d)
3
—
(20 ) —
—
(17 )
Other cost recovery mechanisms:^(e)

Bad debt, energy efficiency programs, and remediation cost riders —
—
1
—
—
1
     Gross receipts tax —
—
(1 ) —
—
(1 )
Total natural gas revenue change $ (4 ) $ —
$ (18 ) $ —
$ —
$ (22 )
Natural gas purchased for resale change:
Effect of weather (estimate)^(b)
$ 5
$ —
$ —
$ —
$ —
$ 5
Purchased natural gas costs – offset in natural gas revenue^(d)
(3 ) —
20
—
—
17
Total natural gas purchased for resale change $ 2
$ —
$ 20
$ —
$ —
$ 22
Net change in natural gas margins $ (2 ) $ —
$ 2
$ —
$ —
$ —



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 ~~an increase~~a decrease in transmission margins of $2$3 million and ~~$11~~$1 million for the ~~three-~~three and ~~six-month~~six months ended June 30, 2018, respectively, compared with the year-ago periods, ~~respectively,~~ at Ameren Illinois.

(b)

Represents the estimated variation resulting primarily from changes in cooling and heating degree-days on electric and natural gas demand compared with the prior year; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories. ~~Beginning in 2017, FEJA eliminated the impact of weather on Ameren Illinois Electric Distribution’s electric margins.~~


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


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

(e)

~~See~~Offsetting increases or decreases to expenses are reflected in “Operating Expenses – Other ~~Operations~~operations and ~~Maintenance~~maintenance” or in “Operating Expenses or– Taxes ~~Other Than Income Taxes in this section for~~other than income taxes” on the ~~related offsetting increase or decrease to expense.~~statement of income. These items have no overall impact on earnings.

Ameren

~~Ameren's~~Ameren’s electric margins increased ~~$72~~$25 million, or 7%2%, and ~~$131~~$76 million, or 8%4%, for the three and six months ended June 30, ~~2017,~~2018, respectively, compared with the year-ago periods, primarily because of increased margins at Ameren ~~Transmission, Ameren~~ Missouri, ~~and~~partially offset by decreased margins at Ameren Illinois Electric Distribution.

Ameren's natural gas margins ~~were comparable between periods.~~

~~Ameren Transmission~~

~~Ameren Transmission's margins~~ increased ~~$13~~$2 million, or ~~14%~~2%, and ~~$32~~$15 million, or ~~18%~~5%, for the three and six months ended June 30, ~~2017,~~2018, respectively, compared with the year-ago ~~periods. The increase in~~periods, primarily because of increased margins ~~was primarily due to capital investment, as evidenced by a 21% increase in rate base used to calculate the revenue requirement~~ at ~~June 30, 2017, compared to June 30, 2016, as well as higher recoverable costs~~Ameren Illinois Natural Gas.

Ameren Transmission

Ameren Transmission's margins were comparable for the three and six months ended June 30, ~~2017,~~2018, compared with the year-ago ~~periods,~~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~~Missouri’s electric margins increased ~~$28~~$50 million, or 4%8%, and ~~$28~~$111 million, or 3%10%, for the three and six months ended June 30, ~~2017,~~2018, respectively, compared with the year-ago periods. ~~Higher electric base rates, effective April 1, 2017,~~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 a result of the March 2017 electric rate order, increased margins by an estimated $36 million for both periods. The change in electric base rates is the sum of the change in base rates (estimate) (+$24 million for both periods) and the effect of lower net energy costs included in base rates (+$12 million for both periods) in the Electric and Natural Gas Margins table above.discussed below.

The following items had ~~an unfavorable~~a favorable effect on Ameren Missouri's electric margins for the three and six months ended June 30, ~~2017,~~2018, compared with the year-ago ~~periods:~~periods (except where a specific period is referenced):

~~Early~~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 ~~milder~~warmer as cooling degree days ~~decreased 3%~~increased 22% for the three months ended June 30, ~~2017, compared with the year-ago period, and winter temperatures were milder as heating degree days decreased 15% for the six months ended June 30, 2017,~~2018, compared with the year-ago period. The effect of weather ~~decreased~~increased margins by an estimated ~~$16~~$58 million and ~~$30~~$94 million, respectively. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-(+$1969 million and ~~-$39~~+$120 million, respectively) and the effect of weather (estimate) on fuel and purchased power (+(-$311 million and ~~+$9~~-$26 million, respectively) in the ~~Electric and Natural Gas Margins~~ table above.

Excluding the estimated ~~effect~~effects of weather and ~~reduced sales to~~ the ~~New Madrid Smelter,~~MEEIA 2016 customer energy-efficiency programs, total retail sales volumes ~~decreased by less than 1% for both periods,~~increased 3% and 2%, respectively, which ~~decreased~~increased margins by $1an estimated $11 million and $6$9 million,~~, respectively. Lower retail sales volumes for the six months ended June 30, 2017, compared with the year-ago period, were~~ respectively, primarily due to ~~the absence of the leap year benefit experienced in 2016 and the effects of the MEEIA programs, partially offset by~~ growth. The throughput disincentive recovery, as part of MEEIA 2016, ensures that electric margins are not affected by reduced sales volumes as a result of MEEIA programs. Lower sales volumes led to a decrease in net energy costs of $2 million for both periods. The change in ~~net energy costs~~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 ~~+$133~~-$123 million, respectively) and the effect of the change in energy costs (excluding the effect of ~~weather and the New Madrid Smelter) (-~~weather) (+$5249 million and ~~-$131~~+$119 million, respectively) in the ~~Electric and Natural Gas Margins~~ 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.

~~Increased transmission services charges resulting from additional MISO-approved~~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 ~~transmission investments made~~margins were unfavorably affected by ~~other entities and shared~~decreased revenues, which reflected expected customer rate reductions in accordance with the TCJA section of Missouri Senate Bill 564, partially offset by ~~all MISO participants, which~~higher electric base rates, as a result of the March 2017 electric rate order. These items collectively decreased margins by $2an estimated $37 million and $23 million for ~~both~~the three and six months ended June 30, 2018, respectively, compared with the year-ago periods.

~~Ameren Missouri’s natural gas margins were comparable between 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 ~~increased by $33~~decreased $24 million, or ~~10%~~7%, and ~~$83~~$37 million, or ~~14%~~5%, for the three and six months ended June 30, ~~2017,~~2018, respectively, compared with the year-ago periods, driven by ~~increases in~~decreased margins at Ameren Illinois Electric ~~Distribution ($31 million and $72 million, respectively) and Ameren Illinois Transmission ($2 million and $11 million, respectively) margins.~~Distribution. Ameren Illinois Natural Gas’ margins were comparable ~~between~~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.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins ~~increased $31~~decreased $21 million, or ~~12%~~7%, and ~~$72~~$36 million, or ~~15%~~6%, for the three and six months ended June 30, ~~2017,~~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, ~~2017,~~2018, compared with the year-ago periods:

~~A change in the method used to recognize interim period revenue, in connection~~The recovery of labor and benefit costs for crews assisting other utilities with ~~the decoupling provisions of the FEJA,~~power restoration efforts, which increased ~~margins by $15~~revenues $2 million and ~~$47~~$10 million, respectively. ~~This change will not impact annual earnings. See Note 2 – Rate and~~

~~Regulatory Matters under Part I, Item 1, of this report for additional information on FEJA and IEIMA.~~

Revenues increased ~~by $15~~$3 million and ~~$21~~$5 million, respectively, ~~primarily~~ due to ~~increased recoverable expenses and rate base, as well as a higher 30-year United States Treasury bond yield under formula ratemaking.~~energy-efficiency program investments pursuant to the FEJA.

~~The absence of the impact of warmer-than-normal early summer temperatures experienced in the second quarter of 2016 and the decoupling of revenues in 2017, decreased~~Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ margins ~~by an estimated $3 million~~were comparable for the three months ended June 30, ~~2017,~~2018, and increased $11 million, or 4%, for the six months ended June 30, 2018, compared with the year-ago ~~period.~~ periods.

The ~~change in margins due to weather is the sum of the~~following items had a favorable effect ~~of weather (estimate)~~ on ~~electric revenues (-$4 million) and the effect of weather (estimate) on fuel and purchased power (+$1 million) in the Electric and Natural Gas Margins table above.~~

Ameren Illinois ~~Transmission~~

~~Ameren Illinois Transmission's~~Natural Gas’ margins ~~increased $2 million, or 3%, and $11 million, or 10%,~~ for the three and six months ended June 30, ~~2017, respectively,~~2018, compared with the year-ago ~~periods. The increase in~~periods:

Revenues from QIP recoveries, which increased margins ~~was primarily~~$6 million and $10 million, respectively, due to ~~capital~~additional investment ~~as evidenced~~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 ~~a 15% increase~~the reduction in the federal statutory corporate income tax rate, ~~base used to calculate the revenue requirement at June 30, 2017, compared to June 30, 2016, as well as higher recoverable costs~~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, ~~2017,~~2018, compared with the year-ago ~~periods,~~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 ~~$13~~$8 million and $8$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.

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, ~~2017,~~2018, respectively, as compared with the year-ago periods ~~as discussed below.~~

~~Ameren Transmission~~

~~Other operations and maintenance expenses were comparable in the three and six months ended June 30, 2017, with the year-ago periods.~~

~~Ameren Missouri~~

~~Other operations and maintenance expenses were $19 million lower for both the three and six months ended June 30, 2017, compared with the year-ago periods. Refueling and maintenance outage costs~~ at the Callaway energy center were lower by $27 million and $31 million, respectively, as a refueling and maintenance outage occurred in the second quarter of 2016 and the next outage is scheduled for the fall of 2017. Additionally, pension and benefit costs decreased by $5 million in both periods and solar rebate amortization costs decreased by $3 million in both periods, as a result of the March 2017 MoPSC electric rate order. Conversely, MEEIA customer energy efficiency program costs increased by $8 million and $16 million, respectively. Electric revenues related to MEEIA program costs increased by a corresponding amount, with no overall effect on net income. Energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center, increased by $3 million and $7 million, respectively, primarily because of higher coal handling charges.

Ameren Illinois,

~~Other operations and maintenance expenses were $10 million and $13 million higher in the three and six months ended June 30, 2017, respectively, compared with the year-ago periods,~~ as discussed below. Other operations and maintenance expenses were comparable in the three and six months ended June 30, ~~2017,~~2018, with the year-ago periods at Ameren Illinois Transmission.

Ameren Illinois Electric Distribution

Other operations and maintenance expenses ~~increased $5~~decreased $14 million and $6$22 million in the three and six months ended June 30, ~~2017,~~2018, respectively, compared with the year-ago periods, primarily because of ~~increased labor~~a decrease of $19 million and $36 million, respectively, in customer energy-efficiency costs ~~attributable to staff additions to meet enhanced standards and goals related~~prior to the ~~IEIMA,~~FEJA. This decrease was partially offset by a $5 million and an$14 million increase in ~~estimated litigation costs. Additionally, bad debt, customer energy efficiency,~~labor and ~~environmental remediation~~benefit costs ~~increased~~ in the three and six months ended June 30, ~~2017, compared with the year-ago period, which are included~~2018, respectively, primarily due to assistance provided to other utilities to aid in ~~cost recovery mechanisms that result in increased electric revenues, with no overall effect on net income.~~power restoration efforts.

Ameren Illinois Natural Gas

Other operations and maintenance expenses increased $5 million and $6 million in the three and six months ended June 30, 2017, respectively, compared with the year-ago periods, primarily because of higher gas pipeline compliance costs, increased pension costs caused by changes in actuarial assumptions and the performance of plan assets, and increased labor costs.

~~Depreciation and Amortization~~

~~Ameren~~

~~Depreciation and amortization expenses increased $12 million and $26 million in the three and six months ended June 30, 2017, respectively, compared with the year-ago periods, as discussed below.~~

~~Ameren Transmission~~

Depreciation and amortization expenses increased $5 million and $9 million in the three and six months ended June 30, 2017, respectively, compared with the year-ago periods, primarily because of additional property, plant, and equipment, as multiple projects were completed in 2016.

~~Ameren Missouri~~

Depreciation and amortization expenses increased $5 million and $11 million in the three and six months ended June 30, 2017, respectively, compared with the year-ago periods, primarily because of additional electric property, plant, and equipment, as multiple projects were completed in 2016.

~~Ameren Illinois~~

Depreciation and amortization expenses increased $5 million in the three months ended June 30, 2017, compared with the year-ago period, primarily because of additional property, plant, and equipment across all Ameren Illinois segments. Depreciation and amortization expenses were comparable in the three months ended June 30, ~~2017, with the year-ago period, at each Ameren Illinois segment. Depreciation~~2018, and ~~amortization expenses~~ increased ~~$11~~$5 million in the six months ended June 30, ~~2017,~~2018, compared with the year-ago ~~period,~~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 at Ameren Illinois Electric Distribution and Ameren Illinois Transmission. Depreciation and amortization expenses were comparable in the six months ended June 30, 2017, with the year-ago period, at Ameren Illinois Natural Gas.investments across their respective segments.

Taxes Other Than Income Taxes

Taxes other than income taxes ~~were comparable~~increased $5 million at ~~each of the~~ Ameren ~~Companies and their respective segments~~ in the three months ended June 30, ~~2017, with the year-ago period. Taxes other than income taxes increased $6 million at Ameren in the six months ended June 30, 2017,~~2018, compared with the year-ago period, primarily because of higher property taxes at Ameren ~~Missouri.~~Illinois Electric Distribution and higher gross receipts taxes at Ameren Illinois Natural Gas. Taxes other than income taxes ~~were comparable~~increased $12 million at Ameren in the six months ended June 30, ~~2017,~~2018, compared with the year-ago period, primarily because of higher gross receipts taxes at Ameren ~~Illinois, as well as at the Ameren Transmission, Ameren Illinois Electric Distribution,~~Missouri and Ameren Illinois Natural ~~Gas, and~~Gas. The increase in gross receipts taxes at Ameren ~~Illinois Transmission segments.~~

~~Other Income and Expenses~~

~~Ameren~~

~~Other income, net of expenses, was comparable in the three months ended June 30, 2017, with the year-ago period. Other income, net of expenses, decreased $8 million~~Missouri in the six months ended June 30, ~~2017,~~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 ~~period,~~periods, as discussed below. See Note 5 – Other Income, ~~and Expenses~~Net under Part I, Item 1, of this report for additional information.

Ameren Transmission

Other income, net, ~~of expenses, was comparable in the three and six months ended June 30, 2017, with the year-ago periods.~~

~~Ameren Missouri~~

~~Other income, net of expenses, was comparable in the three and six months ended June 30, 2017, with the year-ago periods.~~

~~Ameren Illinois~~

~~Other income, net of expenses,~~ was comparable in the three months ended June 30, ~~2017, with the year-ago period, for Ameren Illinois~~2018, and ~~each of its segments. Other income, net of expenses, decreased $5~~increased $3 million in the six months ended June 30, 2017, compared with the year-ago period, primarily because of lower interest income on IEIMA revenue requirement reconciliation regulatory assets and a decrease in the allowance for equity funds used during construction at Ameren Illinois Electric Distribution, resulting from lower eligible construction work in progress balances. Other income, net of expenses, was comparable in the six months ended June 30, 2017, with the year-ago period, for the remaining Ameren Illinois segments.

~~Interest Charges~~

~~Ameren~~

~~Interest charges increased $4 million and $8 million in the three and six months ended June 30, 2017, respectively, compared with the year-ago periods, as discussed below.~~

~~Ameren Transmission~~

~~Interest charges increased $3 million and $5 million in the three and six months ended June 30, 2017, respectively,~~2018, compared with the year-ago periods, primarily because of an increase in ~~average outstanding debt at~~ 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 ~~Illinois, increased interest charges associated~~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 ~~intercompany borrowings at ATXI, and~~the year-ago periods, primarily because of a decrease in the ~~allowance~~non-service cost components of net periodic benefit income. See Note 11 – Retirement Benefits under Part I, Item 1, of this report for ~~borrowed funds used during construction, as multiple projects were completed in 2016 at Ameren Illinois Transmission.~~the non-service cost components of net periodic benefit income.

Ameren ~~Missouri~~Illinois

~~Interest charges were comparable~~Other income, net, increased $10 million and $16 million in the three and six months ended June 30, ~~2017,~~2018, compared with the year-ago ~~periods.~~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 ~~Illinois~~

Interest charges were comparable in the three months ended June 30, ~~2017,~~2018, with the year-ago period ~~for~~at Ameren ~~Illinois~~ and each of its segments. Interest charges increased $3 million in the six months ended June 30, ~~2017,~~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 ~~interest charges~~average outstanding debt at ATXI.

Ameren ~~Illinois Transmission, as discussed above.~~ Missouri

Interest charges ~~were comparable for~~decreased $5 million in the six months ended June 30, ~~2017, compared with~~2018, primarily because of a decrease in the ~~year-ago period, at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas.~~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, ~~2017~~2018 and ~~2016:~~2017:


	Three Months^(a)				Six Months^(a)				Three Months^(a)				Six Months^(a)
	2017		2016		2017		2016		2018		2017		2018		2017
Ameren	37	%	38	%	36	%	33	%	24	%	37	%	23	%	36	%
Ameren Missouri	37	%	38	%	37	%	38	%	24	%	37	%	24	%	37	%
Ameren Illinois	39	%	39	%	39	%	39	%	23	%	39	%	24	%	39	%
Ameren Illinois Electric Distribution	39	%	39	%	39	%	37	%	22	%	39	%	22	%	39	%
Ameren Illinois Natural Gas	39	%	37	%	39	%	39	%	25	%	39	%	26	%	39	%
Ameren Illinois Transmission	39	%	39	%	39	%	39	%	22	%	39	%	25	%	39	%
Ameren Transmission	40	%	40	%	40	%	40	%	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, ~~2017~~2018 and ~~2016.~~2017.

Ameren

The effective income tax rate was comparable in the three months ended June 30, 2017, with the year-ago period. The effective tax rate was higher in the six months ended June 30, 2017, compared with the year-ago period, primarily because of a decrease in the recognition of tax benefits associated with share-based compensation.

~~Ameren Transmission~~

~~The effective tax rate was comparable~~lower in the three and six months ended June 30, ~~2017,~~2018, compared with the year-ago ~~periods.~~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 ~~Missouri~~Transmission

The effective income tax rate was ~~comparable~~lower in the three and six months ended June 30, ~~2017,~~2018, compared with the year-ago ~~periods.~~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 ~~Illinois~~Missouri

The effective income tax rate was ~~comparable~~lower in the three and six months ended June 30, ~~2017,~~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

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 ~~Ameren Illinois Natural Gas,~~ and Ameren Illinois Transmission ~~except as discussed below.~~

~~Ameren Illinois Electric Distribution~~

~~The effective tax rate was higher in the six months ended June 30, 2017, compared with the year-ago period, primarily because of the decreased effect of tax benefits on higher pretax income~~ in the current year ~~from certain depreciation differences on property-related items, tax credits, and company-owned life insurance.~~

~~Ameren Illinois Natural Gas~~

~~The~~also contributed to the lower effective tax rate was higher in the three months ended June 30, 2017, compared with the year-ago period, primarily because of lower tax benefits in the current year from certain depreciation differences on property-related items.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. ~~We intend~~As part of its plan to fund ~~those capital expenditures primarily~~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 ~~cash provided by operating activities~~the long-term intent to maintain strong financial metrics and ~~short-term and long-term debt issuances so that we maintain~~ an equity ratio around 50%, ~~assuming constructive regulatory~~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, ~~2017~~,2018, for the Ameren ~~and Ameren Illinois.~~Companies. The working capital deficit as of June 30, ~~2017,~~2018, was primarily the result of current maturities of long-term debt ~~and our decision to finance our businesses with lower-cost~~as well as commercial paper ~~issuances.~~issuances at Ameren (parent). With the credit capacity available under the Credit Agreements, the Ameren Companies had access to ~~$1.2~~$1.6 billion of liquidity at June 30, ~~2017.~~2018.

The following table presents net cash provided by (used in) operating, investing, and financing activities for the six months ended June 30, ~~2017~~2018 and ~~2016~~:2017:


	Net Cash Provided By Operating Activities							Net Cash Used In Investing Activities									Net Cash Provided by (Used In) Financing Activities								Net Cash Provided By Operating Activities							Net Cash Used In Investing Activities									Net Cash Provided by (Used In) Financing Activities
	2017		2016		Variance			2017			2016			Variance			2017			2016			Variance		2018		2017		Variance			2018			2017			Variance			2018		2017			Variance
Ameren^(a)	$	863	$	763	$	100		$	(1,059	)	$	(1,035	)	$	(24	)	$	197		$	(7	)	$	204	$	820	$	863	$	(43	)	$	(1,129	)	$	(1,059	)	$	(70	)	$	337	$	197		$	140
Ameren Missouri	396		364		32			(253		)	(354		)	101			(143		)	(209		)	66		412		396		16			(543		)	(253		)	(290		)	149		(143		)	292
Ameren Illinois	375		382		(7		)	(480		)	(438		)	(42		)	105			(15		)	120		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 ~~proceeding.~~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 ~~increased $100~~decreased $43 million in the first six months of ~~2017,~~2018, compared with the year-ago period. The following items contributed to the ~~increase:~~

~~A $135 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.~~decrease:

A ~~$29~~$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 ~~payments~~expenditures for ~~scheduled nuclear refueling and maintenance outages~~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 ~~Ameren Missouri Callaway energy center, as a refueling and maintenance outage occurred~~2015 revenue requirement reconciliation adjustment, which was recovered from customers in ~~the second quarter of 2016 and the next outage is scheduled for the fall of~~ 2017.

A ~~$15~~$19 million ~~increase~~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 ~~increase~~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 ~~a $42~~$21 million ~~insurance receipt at Ameren Missouri related to the Taum Sauk breach received~~ in ~~2016.~~

~~Refunds of $21 million~~refunds paid in 2017 associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part I,II, Item 1,8, of ~~this report.~~the Form 10-K.

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

A ~~$19~~$17 million decrease in ~~cash associated~~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 recovery of Ameren Illinois' IEIMA revenue requirement reconciliation adjustments. The 2015 revenue requirement reconciliation adjustment, which is being recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.prior year.

A ~~$16~~$14 million ~~increase~~decrease in pension and postretirement benefit contributions.

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

~~Ameren Missouri~~

~~Ameren Missouri’s cash from operating activities increased $32 million in the first six months of 2017, compared with the year-ago period. The following items contributed to the increase:~~

customers under MEEIA.

A ~~$33~~$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 ~~$29~~$6 million decrease in ~~payments for scheduled nuclear refueling and maintenance outages~~coal inventory at ~~the Callaway energy center, as a refueling and maintenance outage occurred in the second quarter~~Ameren Missouri because of ~~2016 and the next outage is scheduled for the fall of 2017.~~decreased market prices.

~~A $15 million increase in net energy costs collected from customers under the FAC.~~Ameren Missouri

~~The absence of a $42 million insurance receipt related to the Taum Sauk breach received in 2016 partially offset the increase in~~ Ameren Missouri’s cash from operating activities ~~between periods.~~

~~Ameren Illinois~~

~~Ameren Illinois’ cash from operating activities decreased $7~~increased $16 million in the first six months of ~~2017,~~2018, compared with the year-ago period. The following items contributed to the ~~decrease:~~

~~An increase of $24 million in income tax payments paid to Ameren (parent) pursuant to the tax allocation agreement, primarily related to the timing of payments.~~increase:

A $19 million decrease in cash associated with the recovery of IEIMA revenue requirement reconciliation adjustments. The 2015 revenue requirement reconciliation adjustment, which is being recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.

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

~~A $16 million increase in expenditures for customer energy efficiency programs compared with amounts collected from customers.~~

~~An $8 million increase in payments for purchased power compared with amounts collected from customers.~~

~~A $5 million increase in interest payments, primarily due to an increase in the average outstanding debt.~~

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

~~A $4 million increase in labor costs primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals related to the IEIMA.~~

~~Ameren Illinois’ decrease in cash from operating activities was substantially offset by a $95~~$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.

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 ~~$24~~by $70 million in the first six months of ~~2017,~~2018, compared ~~with~~to the year-ago ~~period. Nuclear fuel expenditures increased $26 million~~period, primarily as a result of ~~the activity at Ameren Missouri, as discussed below. Additionally, Ameren Illinois’~~increased capital expenditures ~~increased $42~~of $114 million, ~~as discussed below. This increase was~~ partially offset by a ~~$45~~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 ~~project partially offset by increased expenditures related to the~~and Spoon River ~~project.~~

projects. The Spoon River project was placed in service in February 2018.

Ameren Missouri’s cash used in investing activities ~~decreased $101~~increased by $290 million inbetween periods, primarily due to net money pool advances. In the first six months of ~~2017,~~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 ~~year-ago~~same period ~~due~~in 2017. Additionally, capital expenditures increased $99 million between periods primarily related to ~~a $125 million~~energy center projects and electric distribution system reliability projects. The increase in ~~the return of money pool advances. The decrease~~capital expenditures was partially offset by a ~~$26~~$34 million ~~increase~~decrease in nuclear fuel expenditures ~~because of~~due to the timing of ~~purchases in the first six months of 2017, compared with the prior-year period.~~purchases.

Ameren Illinois’ cash used in investing activities increased ~~$42~~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 ~~distribution and~~ transmission system reliability ~~investments in smart grid technology, and substation upgrades.~~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 ~~provided cash of $197~~increased by $140 million during the first six months of ~~2017,~~2018, compared ~~with $7 million of cash used in financing activities during~~to the ~~first six months of 2016.~~year-ago period. During the first six months of ~~2017,~~2018, Ameren utilized net proceeds ~~of $883 million~~ from the issuance of $874 million of long-term indebtedness and net commercial paper issuances to repay ~~at maturity $425~~$323 million of ~~higher cost~~higher-cost long-term indebtedness and to fund, in part, investing activities. In comparison, during the first six months of ~~2016,~~2017, Ameren ~~used~~utilized net proceeds ~~of $626 million~~ from the issuance of $883 million of long-term indebtedness and net commercial paper issuances to ~~redeem at maturity $389~~repay $425 million of ~~higher cost~~higher-cost long-term indebtedness and to fund, in part, investing activities.

Additionally, Ameren ~~Missouri’s cash used~~issued $40 million in ~~financing activities decreased $66 million~~common stock under its DRPlus and 401(k) plan in the first six months of ~~2017, compared with the year-ago period. During the first six months of 2017,~~2018. Ameren ~~Missouri~~also issued ~~$399 million of long-term indebtedness and used the proceeds, along with proceeds from net commercial paper issuances,~~common stock related to ~~repay at maturity $425 million of higher cost long-term indebtedness. In comparison,~~stock-based compensation resulting in noncash financing activity during the first six months of ~~2016,~~2018, compared with $24 million paid for the repurchase of common stock for stock-based compensation in the year-ago period. Ameren Missouri issued $149 million of long-term indebtedness and used the proceeds, along with proceeds from net commercial paper issuances and cash on hand, to repay at maturity $260 million of higher cost long-term indebtedness. In addition, duringdid not issue common stock in the first six months of ~~2017, Ameren Missouri paid $172 million in common stock dividends compared with $210 million in dividend payments in the year-ago period.~~2017.

Ameren ~~Illinois’~~Missouri’s financing activities provided cash of ~~$105~~$149 million during the first six months of ~~2017,~~2018, compared ~~with $15~~to using cash of $143 million ~~of cash used in financing activities~~ during the ~~first six months of 2016.~~same period in 2017. During the first six months of ~~2017,~~2018, Ameren ~~Illinois used~~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, ~~of $108 million~~and to fund, in part, investing activities. In comparison, during the first six months of ~~2016,~~2017, Ameren ~~Illinois used~~Missouri utilized net proceeds from the issuance of $459 million of long-term indebtedness and net commercial paper issuances to repay ~~at maturity $129~~$425 million of ~~higher cost~~higher-cost long-term ~~indebtedness.~~indebtedness and to fund, in part, investing activities. Additionally, during the first six months of 2018, Ameren ~~Illinois did not pay~~Missouri paid $50 million in common stock dividends, ~~during the six months ended June 30, 2017,~~ compared towith $172 million in dividend payments ~~of $60~~in the year-ago period.

Ameren Illinois’ cash provided by financing activities increased by $223 million during the ~~same period~~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 ~~2016.~~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, ~~commercial paper issuances,~~or proceeds from short-term ~~intercompany~~affiliate borrowings, ~~or drawings~~borrowings under the Credit ~~Agreements.~~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 ~~the Credit Agreements, short-term borrowing activity,~~credit agreements, commercial paper issuances, ~~relevant interest rates, and~~ borrowings under Ameren’s money pool ~~arrangements.~~arrangements, and relevant interest rates.

The following table presents Ameren’s consolidated liquidity as of June 30, ~~2017~~2018:


Ameren and Ameren Missouri:
Ameren (parent) and Ameren Missouri:
Missouri Credit Agreement – borrowing capacity	$	1,000	$	1,000
Less: Ameren (parent) commercial paper outstanding	393		295
Less: Ameren Missouri commercial paper outstanding	60
Missouri Credit Agreement – credit available	547		705
Ameren and Ameren Illinois:
Ameren (parent) and Ameren Illinois:
Illinois Credit Agreement – borrowing capacity	1,100		1,100
Less: Ameren (parent) commercial paper outstanding	280		211
Less: Ameren Illinois commercial paper outstanding	159
Less: Letters of credit	4		1
Illinois Credit Agreement – credit available	657		888
Total Credit Available	$	1,204	$	1,593
Cash and cash equivalents	10		29
Total Liquidity	$	1,214	$	1,622

The Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under ~~Ameren’s~~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’s~~Ameren (parents)’s commercial paper program, subject to ~~borrowing sublimits.~~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 ~~available~~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 ~~offers~~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 ~~June 2017,~~March 2018, the FERC issued an order authorizing ~~ATXI~~Ameren Missouri to issue up to ~~$300 million~~$1.0 billion of short-term debt securities through ~~July 2019.~~March 2020.

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

Long-term Debt and Equity

The following table presents ~~the~~Ameren’s equity issuances, as well as issuances (net of any issuance premiums or discounts), ~~maturities,~~redemptions, repurchases, and ~~redemptions~~maturities of long-term debt for Ameren Missouri, Ameren Illinois, and ATXI for the six months ended June 30, ~~2017~~2018 and 2016. The Ameren Companies did not issue any common stock during the first six months of 2017 or 2016. In March 2016, Ameren Missouri received cash capital contributions of $38 million from Ameren (parent).2017.


	Month Issued, Redeemed, or Matured	2017		2016		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	$	—	June	—			399
3.65% Senior secured notes due 2045	June	—		149
Ameren Illinois:
3.80% First mortgage bonds due 2028						May	430			—
ATXI:
3.43% Senior notes due 2050	June	$	150	$	—	June	—			150
Total Ameren long-term debt issuances		$	549	$	149		$	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	$	—	June	—			425
5.40% Senior secured notes due 2016	February	—		260
Ameren Illinois:
6.20% Senior secured notes due 2016	June	—		54
6.25% Senior secured notes due 2016	June	—		75
6.25% Senior secured notes due 2018						May	144			—
Total Ameren long-term debt redemptions and maturities		$	425	$	389		$	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.

~~In June 2017, Ameren Missouri issued $400 million~~See Note 4 – Long-Term Debt and Equity Financings under Part 1, Item 1, of ~~2.95% senior secured notes due June 2027, with interest payable semiannually on June 15~~this report for additional information, including proceeds from issuances of long-term debt and ~~December 15~~use of each year, beginning December 15, 2017. Ameren Missouri received proceeds of $396 million, which were used, in conjunction with other available funds, to repay at maturity $425 million of Ameren Missouri’s 6.40% senior secured notes in June 2017.

In June 2017, pursuant to a note purchase agreement, ATXI agreed to issue $450 million principal amount of 3.43% senior unsecured notes due 2050 through a private placement offering exempt from registration under the Securities Act of 1933, as amended. ATXI issued $150 million principal amount of the notes in June 2017 and has agreed to issue the remaining $300 million principal amount of the notes in August 2017, subject to certain conditions. The proceeds of the notes, of which $149 million were received in June 2017, were, and will be used, by ATXI to repay existing short-term and long-term affiliate debt owed to Ameren (parent).those proceeds.

Indebtedness Provisions and Other Covenants

See Note 3 – Short-term Debt and Liquidity ~~and Note 4 – Long-term Debt and Equity Financings~~ under Part I, Item 1, of this report and

Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of the Form 10-K for a discussion of ~~covenants and~~ provisions (and applicable cross-default provisions) 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, ~~2017,~~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 ~~generated from~~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 ~~dividends~~ are within the sole discretion of Ameren’s board of directors. Ameren’s board of directors has not set specific targets or payout parameters when declaring common stock dividends, but it considers various factors, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow

requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. Ameren expects its dividend payout ratio to be between 55% and 70% of 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, ~~2017~~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 ~~Missouri and Ameren Illinois~~subsidiaries to their parent, Ameren Corporation, for the six months ended June 30, ~~2017~~2018 and ~~2016~~2017:


	Six Months				Six Months
	2017		2016		2018		2017
Ameren Missouri	$	172	$	210	$	50	$	172
Ameren Illinois	—		60		—		—
ATXI					25		—
Ameren	214		206		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 1110 – Retirement Benefits under Part I,II, Item 1,8, of ~~this report~~the Form 10-K for information regarding expected minimum funding levels for our pension plan.

At June 30, ~~2017,~~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 ~~$3,655~~$2,058 million, ~~$2,145~~$1,227 million, and ~~$1,444~~$779 million, respectively.

~~Off-Balance-Sheet~~Off-balance-sheet Arrangements

At June 30, ~~2017~~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~~(parent) guarantee arrangements on behalf of its subsidiaries. ~~None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.~~

Credit Ratings

~~The~~Our credit ratings ~~of the Ameren Companies and ATXI assigned by Moody’s and S&P, as applicable, can~~ 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 ~~of the Ameren Companies and ATXI,~~ 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

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 ~~Ameren, Ameren Missouri, and Ameren Illinois at~~ June 30, ~~2017.~~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, ~~2017,~~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 ~~$96~~$99 million, ~~$59~~$52 million, and ~~$37~~$47 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at June 30, ~~2017,~~2018, if market prices were 15% higher or lower than June 30, ~~2017~~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 ~~are seeking~~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 ~~are seeking to~~ align our overall spending, both operating and capital, with economic conditions and with ~~regulatory~~the frameworks established by our regulators and to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We ~~are focused~~focus on minimizing the gap between allowed and earned returns on equity and ~~intend to allocate~~allocating capital resources to ~~our~~ business opportunities that we expect towill offer the most attractive risk-adjusted return potential.

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

Below are some key trends, events, and uncertainties that ~~are~~may reasonably ~~likely to~~ affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for ~~2017~~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.

~~Operations~~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. ~~MISO~~ATXI has ~~approved~~ three ~~electric transmission projects to be developed by ATXI.~~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 ~~the state of~~ 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 ~~Spoon River project, located in northwest Illinois, and the~~ Mark Twain project ~~located in~~involves the construction of a transmission line from northeast Missouri, ~~and~~ connecting the Illinois Rivers project to ~~Iowa, are the other two MISO-approved projects to be constructed by ATXI.~~Iowa. Construction activities for the ~~Spoon River~~Mark Twain project are continuing on schedule and ~~the project is~~are expected to be completed by the end of 2019. ATXI’s expected remaining investment in ~~2018. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding~~its multi-value projects is approximately $300 million from 2018 through 2019, with the ~~Mark Twain project and its approval process. The~~ total investment ~~in all three projects is expected~~ to be more than ~~$575 million from 2017 through 2019.~~$1.6 billion. In addition, Ameren Illinois expects to invest ~~$2.2~~$2.3 billion in electric transmission assets from ~~2017~~2018 through ~~2021~~2022, to replace aging infrastructure and improve reliability.

~~Both~~ Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Based on ~~the rates that became effective on January 1, 2017,~~expected rate base growth and the currently allowed 10.82% return on common equity, the ~~2017~~2018 revenue ~~requirement~~requirements included in rates for Ameren Illinois’ ~~electric transmission business is $258 million. The 2017 revenue requirement represents a $33 million increase over the revised 2016 revenue requirement, which became effective in September 2016,~~ and was based on a 10.82% return on common equity. These January 2017 rates reflect a capital structure comprised of 51.6% common equity and a projected average rate base of $1.4 billion. Based on the rates that became effective on January 1, 2017, and the currently allowed 10.82% return on equity, the 2017 revenue requirement for ATXI’s electric transmission ~~business is $171 million. The 2017~~businesses are $273 million and $174 million, respectively. These revenue ~~requirement represents a $44~~requirements represent an increase in Ameren Illinois' and ATXI's revenue requirements of $12 million ~~increase over~~and $3 million, respectively, primarily because of the revised 2016 revenue requirement, which became effective in September 2016, and was based on a 10.82% return on common equity. These January 2017 rates reflect a capital structure comprised of 56.3% common equity and a projected average rate base ~~of $1.1 billion, reflecting additional investment in~~growth, partially offset by a decrease due to the ~~Illinois Rivers project.~~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, ~~was~~is the subject of ~~two~~a FERC complaint ~~proceedings, the November 2013 complaint~~ case ~~and the~~filed in February 2015 ~~complaint case, that each challenged~~challenging the allowed base return on common equity. ~~In September 2016,~~Ameren Illinois and ATXI currently use the FERC ~~issued a final order in the November 2013 complaint case, which lowered the allowed base return on common equity for the 15-month period of November 2013 to February 2015 to 10.32%, or a 10.82%~~authorized total allowed return on common equity ~~with~~of 10.82% in customer rates. A final FERC order would establish the ~~inclusion of a 50 basis point incentive adder for participation in an RTO. The order required customer refunds, with interest, to be issued for that 15-month period.~~ ~~Refunds for the November 2013 complaint case were issued in the first six months of 2017.~~ ~~In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case, which, if approved by the FERC, would lower the~~ allowed ~~base~~ return on common equity ~~for~~to be applied to the 15-month period offrom February 2015 to May 2016 and also establish the return on common equity to ~~9.70%, or a 10.20%~~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 ~~with the inclusion of~~that may be ordered as a ~~50 basis point incentive adder for participation in an RTO and require customer refunds, with interest, for that 15-month period.~~ ~~The timing~~result of the ~~issuance of the final order in the February 2015~~ complaint case is ~~uncertain for two reasons.~~ First, while the FERC reestablished a quorum of three commissioners in August 2017, they are under no deadline to issue a final order. Second, 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.uncertain. A 50 basis point reduction in the FERC-allowed base return on common equity would reduce ~~Ameren's~~Ameren’s and Ameren ~~Illinois'~~Illinois’ annual earnings by an estimated $7$8 million and $4 million, respectively, based on each company’s ~~2017~~2018 projected rate base. Ameren and Ameren Illinois recorded current regulatory liabilities on their respective June 30, 2017 balance sheets, representing their estimate of the expected refunds related to the February 2015 complaint case.

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

Illinois law provides for an annual reconciliation of the electric distribution 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' ~~2017~~2018 electric distribution service revenues will be based on its ~~2017~~2018 actual recoverable costs, rate base, and return on common equity as calculated under the Illinois performance-based formula ratemaking framework. The ~~2017~~2018 revenue requirement is expected to be ~~higher than~~comparable to the ~~2016~~2017 revenue requirement because of an expected increase in recoverable costs, expected rate base growth, ~~of 5%,~~ and an expected increase in the monthly average yield of 30-year United States ~~treasury bonds.~~Treasury bonds, partially offset by a decrease due to the lower federal statutory corporate income tax rates enacted under the TCJA. The ~~2017~~2018 revenue

requirement reconciliation is expected to result in a regulatory asset that will be collected from customers in ~~2019.~~2020. A 50 basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $7$8 million change in ~~Ameren's~~Ameren’s and Ameren ~~Illinois'~~Illinois’ net income, based on Ameren Illinois’ ~~2017~~2018 projected year-end rate base.

In April ~~2017,~~2018, Ameren Illinois filed ~~with the ICC~~ its annual electric distribution service formula rate update to establish the revenue requirement to be used for ~~2018 rates.~~2019 rates with the ICC. In ~~June 2017,~~July 2018, the ICC staff submitted its calculation of the revenue requirement ~~which~~included in Ameren ~~Illinois supported in its revised July 2017~~Illinois’ update filing, ~~and recommended a decrease~~recommending an amount comparable to ~~the electric distribution service revenue requirement.~~Ameren Illinois’ filing. Pending ICC approval, this update filing will result in a ~~$17~~$72 million ~~decrease~~increase in Ameren Illinois’ electric distribution service ~~revenue requirement~~rates beginning in January ~~2018.~~2019. These rates will affect Ameren Illinois' cash receipts during ~~2018,~~2019, but will not determine its electric distribution service operating revenues, which will instead be based on its ~~2018~~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 ~~2018~~2019 rates is expected by December ~~2017.~~2018.

~~Beginning in 2017, the FEJA provides that~~ Ameren Illinois recovers, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes. In connection with the decoupling provisions of the FEJA, Ameren Illinois changed its method used to recognize its interim period revenue. Ameren Illinois now recognizes revenues consistent with the timing of incurred electric distribution recoverable costs and recognizes revenue associated with the expected return on its rate base ratably over the year. As a result of this change in recognition of the interim period revenue for the IEIMA formula rate framework, as modified by FEJA, Ameren Illinois expects quarterly year-over-year increases to earnings in 2017 in comparison to 2016 for the first, second, and fourth quarters and a decrease to earnings in the third quarter. Ameren Illinois expects an estimated $57 million decrease to earnings in the third quarter of 2017 and an estimated $28 million increase to earnings in the fourth quarter of 2017 as a result of the change. The change in interim period revenue recognition will not impact 2017’s annual earnings.

~~In June 2017, the FEJA began to allow Ameren Illinois~~is allowed to earn a return on its electric ~~energy efficiency~~energy-efficiency program investments. Ameren ~~Illinois~~Illinois’ electric ~~energy efficiency~~energy-efficiency investments ~~will be~~are deferred as a regulatory asset and ~~will~~ earn a return at the company’s ~~weighted average~~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~~energy-efficiency investments can ~~also~~ be increased or decreased by up to 200 basis points, ~~based~~depending on the achievement of annual energy savings goals. ~~Based on a formula provided in~~Pursuant to the FEJA, Ameren Illinois ~~estimates it can annually~~plans to invest up to ~~$100~~$99 million per year in electric energy-efficiency programs from 2018 through 2021 upthat will earn a return. Ameren Illinois plans to ~~$107 million annually~~make similar yearly investments in electric energy-efficiency programs from 2022 ~~through 2025, and up to $114 million annually from 2026~~ through 2030. The ICC has the ability to ~~lower the~~reduce electric ~~energy efficiency saving~~energy-efficiency savings goals if there are insufficient ~~cost effective measures~~cost-effective programs available or if ~~achieving~~ the savings goals would require investment levels that

exceed ~~the formula~~ amounts ~~shown above.~~allowed by legislation. The electric ~~energy efficiency~~energy-efficiency program investments and the return on those investments ~~will be recovered~~are being collected from customers through a ~~rider, and~~rider; they will not be included in the IEIMA formula ~~rate process.~~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 ~~2017,~~2018, Ameren Illinois and the ~~Illinois legislature passed~~ICC staff filed a ~~bill~~stipulation and agreement with the ICC that, ~~increased~~pending ICC approval, would result in an annual natural gas rate increase of $37 million, based on the ~~state's~~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 ~~from~~ ~~7.75% to 9.5%~~ as a result of ~~July 1, 2017. The bill made~~the TCJA, as well as the increase in the ~~state’s~~Illinois corporate income taxrate that became effective in July 2017, which ~~was previously scheduled~~decreased the annual rates by approximately $17 million. In an attempt to ~~decrease to~~ ~~7.3% in 2025,~~ ~~permanent. Ameren's consolidated 2017 net income is expected to decrease by~~ ~~$15 million~~, including an expense of $14 million at Ameren (parent), due to the revaluation of accumulated deferred taxes and the estimated state apportionment of such taxes. Beyond this decrease, Ameren does not expect this tax increase to have a material impact on its consolidated net income prospectively. The tax increase is not expected to materially impact the earnings of thereduce regulatory lag, Ameren Illinois Electric Distribution, Ameren Transmission, nor Ameren Illinois Transmission segments since these businesses operate under formula ratemaking frameworks. The tax increase is expected to unfavorably affect 2017 net income of the Ameren Illinois Natural Gas segment by less than ~~$1 million. The Ameren Illinois Natural Gas segment will continue to be impacted by the tax increase by approximately $1 million annually until~~used a ~~rate review is filed and customer rates are reset in the next rate review.~~

In early 2018, Ameren Illinois expects to file for a natural gas regulatory rate review with the ICC. Ameren Illinois’ current allowed return on equity for natural gas delivery service is 9.60%, with a capital structure of 50% common equity, a rate base of $1.2 billion, and a 20162019 future test ~~year.~~year in this proceeding.

~~The~~Ameren Missouri’s next scheduled refueling and maintenance outage at ~~Ameren Missouri’s~~its Callaway energy center ~~will be in fall 2017.~~is scheduled for the spring of 2019. During the 2017 refueling, Ameren Missouri ~~expects to incur $32 million of~~incurred maintenance expenses ~~which approximates the cost~~ of ~~the spring 2016 outage.~~$35 million. During a ~~scheduled outage,~~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~~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 Ameren Missouri expect an approximately $15 million decrease in annual interest charges as a result of Ameren Missouri’s maturity of $425 million 6.40% senior secured notes and an issuance of $400 million 2.95% senior secured notes in 2017.

As we continue to make infrastructure investments and to experience cost increases, Ameren Missouri and Ameren Illinois expect to seek regular electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. Ameren Missouri and Ameren Illinois will also seek legislative solutions, as necessary, to address regulatory lag and to support investment in their utility infrastructure forrelated transportation contracts. Substantially all the benefit of ~~their customers. Ameren Missouri and Ameren Illinois continue~~these lower costs would be passed through to ~~face cost recovery pressures, including limited economic growth in their service territories, customer conservation efforts,~~customers through the impacts of additional customer energy efficiency programs, and increased customer use of increasingly cost-effective technological advances including private generation and storage. Increased investments, including expected future investments for environmental compliance, system reliability improvements, and new generation capacity, including renewable energy requirements, result in rate base earnings growth but also higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs, higher property taxes, and higher state income taxes, among other costs.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, ~~the Westinghouse bankruptcy filing,~~ and pending requests filed with state and federal regulatory commissions, see Note 2 – Rate and Regulatory Matters ~~and Note 10 – Callaway Energy Center~~ under Part I, Item 1, of this ~~report and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K.~~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 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 ~~2021,~~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 ~~in total~~ up to ~~$11.2~~$11.4 billion (Ameren Missouri –- up to ~~$4.2~~$4.5 billion; Ameren Illinois – up to ~~$6.4~~$6.6 billion; ATXI – up to ~~$0.6~~$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 ~~2021.~~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 CO₂emissions, 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, ~~and~~ increased operating costs, ~~for Ameren and Ameren Missouri. These costs could result in~~or the closure or alteration of some of Ameren ~~Missouri's~~Missouri’s coal-fired energy centers. Ameren ~~Missouri's~~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~~Ameren’s and Ameren ~~Missouri's~~Missouri’s earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in customer rates.

Ameren Missouri files a nonbinding integrated resource plan with the MoPSC every three years and will file its next plan in October 2017. Ameren Missouri’s integrated resource plan filed with the MoPSC in October 2014, prior to the issuance of the Clean Power Plan, was a 20-year plan that supported a more diverse energy generation portfolio in Missouri, including coal, solar, wind, natural gas, hydro and nuclear power. The plan involves expanding renewable generation, retiring coal-fired generation as those energy centers reach the end of their useful lives, expanding customer energy efficiency programs, and adding natural gas-fired combined cycle generation.

The Ameren Companies have multiyear credit agreements that cumulatively provide $2.1 billion of credit through December 2021, subject to a 364-day repayment term in the case of Ameren Missouri and Ameren Illinois. See Note 43 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information regarding the Credit Agreements. By the end of ~~2018, $378~~2019, $772 million and ~~$707~~$312 million of senior secured notes are ~~scheduled~~due to mature at Ameren Missouri and Ameren Illinois, respectively. Ameren Missouri and Ameren Illinois expect to refinance these senior secured ~~notes, as well as~~notes. In addition, the Ameren Companies may refinance a portion of ~~any outstanding~~their short-term debt ~~at the time,~~ with long-term ~~debt.~~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.

~~In December 2015,~~

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 ~~federal~~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 ~~law was enacted that authorized~~depreciation on nearly all capital investments, which has the ~~continued use~~effect of ~~bonus depreciation which allows for an acceleration of deductions for~~increasing Ameren’s near-term projected income tax ~~purposes at a rate of 50% through 2017. The rate will be reduced to 40% in 2018 and to 30% in 2019. Bonus depreciation will be phased out in 2020 unless a new law is enacted.~~liabilities. Ameren expects to ~~use this incremental~~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 ~~flow~~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 ~~make capital investments in utility infrastructure for the benefit of its customers. Without these investments, bonus depreciation would reduce~~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

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 ~~reduces our revenue requirements and future earnings growth. The impact~~certain plant-related components of ~~bonus depreciation on~~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 ~~vary based~~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 ~~investment levels at each company.~~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, ~~2017,~~2018, Ameren had ~~$564~~$155 million in tax benefits from federal and state net operating loss carryforwards ~~(Ameren Missouri – $36 million~~ and ~~Ameren Illinois – $149 million) and $124~~$123 million in federal and state income tax credit carryforwards. These carryforwards ~~(Ameren Missouri – $30 million and Ameren Illinois – $2 million). In addition, Ameren has $25 million of~~are expected ~~state~~to partially offset income tax ~~refunds and state overpayments.~~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, ~~these carryforwards~~Ameren Missouri and Ameren Illinois are expected to

~~partially offset income tax liabilities for Ameren Missouri through 2019 and Ameren Illinois until 2021. Based on existing tax laws, Ameren does not expect to~~ make ~~material federal~~ income tax payments ~~until 2021. These tax benefits, primarily at the~~to Ameren (parent) ~~level, when realized,~~in 2018.

In August 2018, the IRS proposed regulations that would ~~be available~~clarify certain provisions of TCJA related to ~~support funding Ameren Transmission investments.~~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 ~~use debt~~continue to ~~fund such cash shortfalls; it does not currently expect to issue equity~~do so over the next ~~several~~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, orand liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, orand liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase ~~Ameren's~~Ameren’s shareholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position, or liquidity.

REGULATORY MATTERS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

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

~~With the exception of the following, there~~There have been no material changes to the quantitative and qualitative disclosures about interest rate risk, credit risk, equity price risk, commodity price risk, and commodity supplier risk included in the Form 10-K. In the first quarter of 2017, Ameren Missouri’s supplier of nuclear fuel assemblies, Westinghouse, filed a voluntary petition for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. At this time, Ameren and Ameren Missouri believe the restructuring proceeding will not affect Westinghouse’s performance under the terms of its existing contracts with Ameren Missouri, and therefore do not expect any material impact to Ameren Missouri’s operations as a result of this restructuring proceeding. Ameren Missouri has received all necessary fuel assemblies for the fall 2017 refueling and maintenance outage. See Note 10 – Callaway Energy Center under Part I, Item 1, of this report for additional information. See Item 7A under Part II of the Form 10-K for a more detailed discussion of our market risk.

Fair Value of Contracts

We use derivatives principally to manage the risk of changes in market prices for natural gas ~~power,~~ and ~~uranium,~~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, ~~2017.~~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									Three Months									Six Months
	Ameren Missouri			Ameren Illinois			Ameren			Ameren Missouri			Ameren Illinois			Ameren			Ameren Missouri			Ameren Illinois			Ameren			Ameren Missouri			Ameren Illinois			Ameren
Fair value of contracts at beginning of period, net	$	(7	)	$	(204	)	$	(211	)	$	(4	)	$	(180	)	$	(184	)	$	3		$	(219	)	$	(216	)	$	8		$	(217	)	$	(209	)
Contracts realized or otherwise settled during the period	(2		)	4			2			(4		)	2			(2		)	(3		)	8			5			(7		)	14			7
Fair value of new contracts entered into during the period	13			—			13			13			(1		)	12			7			—			7			8			(1		)	7
Other changes in fair value	(2		)	(5		)	(7		)	(3		)	(26		)	(29		)	3			(2		)	1			1			(9		)	(8		)
Fair value of contracts outstanding at end of period, net	$	2		$	(205	)	$	(203	)	$	2		$	(205	)	$	(203	)	$	10		$	(213	)	$	(203	)	$	10		$	(213	)	$	(203	)

The following table presents maturities of derivative contracts as of June 30, ~~2017~~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			Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 3-5 Years			Maturity in Excess of 5 Years			Total Fair Value
Ameren Missouri:
Level 1	$	(3	)	$	(1	)	$	—		$	—		$	(4	)	$	6		$	2		$	—		$	—		$	8
Level 2^(a)	(3		)	(4		)	—			—			(7		)	(4		)	(3		)	—			—			(7		)
Level 3^(b)	13			—			—			—			13			7			2			—			—			9
Total	$	7		$	(5	)	$	—		$	—		$	2		$	9		$	1		$	—		$	—		$	10
Ameren Illinois:
Level 1	$	—		$	1		$	—		$	—		$	1		$	—		$	(1	)	$	—		$	—		$	(1	)
Level 2^(a)	(7		)	(5		)	—			—			(12		)	(8		)	(9		)	(1		)	—			(18		)
Level 3^(b)	(14		)	(27		)	(28		)	(125		)	(194		)	(16		)	(30		)	(30		)	(118		)	(194		)
Total	$	(21	)	$	(31	)	$	(28	)	$	(125	)	$	(205	)	$	(24	)	$	(40	)	$	(31	)	$	(118	)	$	(213	)
Ameren:
Level 1	$	(3	)	$	—		$	—		$	—		$	(3	)	$	6		$	1		$	—		$	—		$	7
Level 2^(a)	(10		)	(9		)	—			—			(19		)	(12		)	(12		)	(1		)	—			(25		)
Level 3^(b)	(1		)	(27		)	(28		)	(125		)	(181		)	(9		)	(28		)	(30		)	(118		)	(185		)
Total	$	(14	)	$	(36	)	$	(28	)	$	(125	)	$	(203	)	$	(15	)	$	(39	)	$	(31	)	$	(118	)	$	(203	)


(a)	Principally fixed-price vs. floating ~~over-the-counter~~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, ~~2017~~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, ~~2017~~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 ~~2017;~~2018;

~~ATXI’s lawsuits~~Ameren Illinois’ annual electric energy efficiency formula rate update filed with the ICC in ~~October 2016~~June 2018;

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

Ameren Missouri’s MEEIA filing with the ~~circuit courts of each of Knox, Marion, Schuyler, and Shelby counties~~MoPSC in ~~Missouri to obtain assents for road crossings in the counties where the Mark Twain transmission project would be constructed if the alternative route is not approved;~~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;

litigation against Ameren Missouri ~~related~~with respect to the ~~EPA~~ Clean Air Act;

and

remediation matters associated with former MGP and waste disposal sites of the Ameren ~~Companies; and~~

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

ITEM 1A. RISK FACTORS.

~~A detailed discussion of our~~There have been no material changes to the risk factors ~~is included~~disclosed in Part I, Item 1A, Risk Factors in the Form 10-K. ~~The information presented below updates, and should be read in conjunction with, the risk factors and information disclosed in the Form 10-K.~~

~~Our operations are subject to acts of terrorism, cyber attacks, and other intentionally disruptive acts.~~

Like other electric and natural gas utilities, our energy centers, fuel storage facilities, transmission and distribution facilities, and information systems may be affected by terrorist activities and other intentionally disruptive acts, including cyber attacks, which could disrupt our ability to produce or distribute our energy products. Within our industry, there have been attacks on energy infrastructure such as power plants, substations, and related assets in the past, and there may be more attacks in the future. Any such incident could limit our ability to generate, purchase, or transmit power or natural gas and could have significant regional economic consequences. Any such disruption could result in a significant decrease in revenues, a significant increase in costs including those for repair, or adversely impact economic activity in our service territory which could adversely affect our results of operations, financial position, and liquidity.

Our industry has seen an increase in the number and sophistication of cyber attacks. A security breach at our physical assets or in our information systems could affect the reliability of the transmission and distribution system, disrupt electric generation, including nuclear generation, and/or subject us to financial harm associated with theft or inappropriate release of certain types of information, including sensitive customer and employee data. Many of our suppliers, vendors, contractors, and information technology providers have access to our systems that support our operations and maintain customer and employee data. A breach of these third-party systems could adversely affect our business as if it was a breach of our own system. If a significant breach occurred, our reputation could be adversely affected, customer confidence could be diminished, or we could be subject to legal claims, any of which could result in a significant decrease in revenues or significant costs for remedying the impacts of such a breach. Our generation, transmission, and distribution systems are part of an interconnected system. Therefore, a disruption caused by a cyber incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our businesses. In addition, new regulations could require changes in our security measures and result in increased costs. The occurrence of any of these events could adversely affect our results of operations, financial position, and liquidity.

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

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

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

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

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

(d) Maximum Number
(or Approximate Dollar Value) of
Shares (or Units) that May Yet
Be Purchased Under the Plans or
Programs
April 1 – April 30, 2017 —
—
—
—
May 1 – May 31, 2017 503
54.24
—
—
June 1 – June 30, 2017 3,701
57.05
—
—
Total 4,204
$ 56.72
—
—

~~(a)~~

The May shares of Ameren common stock were purchased in open-market transactions in satisfaction of Ameren’s obligations for Ameren board of directors’ compensation awards issued under its stock-based compensation plans. The June shares of Ameren common stock were purchased in open-market transactions in satisfaction of Ameren’s obligation to distribute shares of common stock for vested performance units issued under its stock-based compensation plans. Ameren does not have any publicly announced equity securities repurchase plans or programs.

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, ~~2017~~2018 to June 30, ~~2017~~2018.

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 ~~Indenture Company Order, dated June 15, 2017, establishing the 2.950% Senior Notes~~Mortgage for 4.000% First Mortgage Bonds due ~~2027 (including the global note)~~2048	~~June 15, 2017~~April 6, 2018 Form 8-K, ~~Exhibits~~Exhibit 4.2, ~~and 4.3,~~ File No. 1-2967
4.2	Ameren Ameren ~~Missouri~~Illinois	Supplemental ~~Secured~~ Indenture, dated as of May 1, 2018, to ~~the~~ Ameren ~~Missouri~~Illinois Mortgage ~~dated June 1, 2017 relative to Series RR~~for 3.80% First Mortgage Bonds due 2028	~~June 15, 2017~~May 22, 2018 Form 8-K, Exhibit ~~4.5,~~4.2, File No. ~~1-2967~~
~~4.3~~	~~Ameren~~	~~Note Purchase Agreement, dated June 22, 2017, between Ameren Transmission Company of Illinois and the several purchasers named therein~~	~~June 22, 2017 Form 8-K, Exhibit 4.1, File No. 1-14756~~1-3672
Statement re: Computation of Ratios
12.1	Ameren	~~Ameren's~~ Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.2	Ameren Missouri	Ameren ~~Missouri's~~Missouri’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.3	Ameren Illinois	Ameren Illinois’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
Rule 13a-14(a) / 15d-14(a) Certifications
31.1	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren
31.2	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren
31.3	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Missouri
31.4	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Missouri
31.5	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois
31.6	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois
Section 1350 Certifications
32.1	Ameren	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren
32.2	Ameren Missouri	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri
32.3	Ameren Illinois	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Illinois
Interactive Data Files
101.INS	Ameren Companies	XBRL Instance Document
101.SCH	Ameren Companies	XBRL Taxonomy Extension Schema Document
101.CAL	Ameren Companies	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	Ameren Companies	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Ameren Companies	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	Ameren Companies	XBRL Taxonomy Extension Definition Document

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

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

SIGNATURES

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

AMEREN CORPORATION

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

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

UNION ELECTRIC COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

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

AMEREN ILLINOIS COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

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

Date: August ~~4, 2017~~7, 2018

6170



Payment Date		Principal Payment
August 2022	$	49.5
August 2024		49.5
August 2027		49.5
August 2030		49.5
August 2032		49.5
August 2038		49.5
August 2043		76.5
August 2050		76.5
Total Principal Amount of Notes	$	450.0



Period	(a) Total Number of Shares (or Units) Purchased ^(a)	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
April 1 – April 30, 2017	—	—		—	—
May 1 – May 31, 2017	503	54.24		—	—
June 1 – June 30, 2017	3,701	57.05		—	—
Total	4,204	$	56.72	—	—