Edgar Filing: AMEREN CORP

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



ý	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Quarterly Period Ended September 30, 2017



¨	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 October 31, 2017, was as follows:



Ameren Corporation		Common stock, $0.01 par value per share – 242,634,798
Union Electric Company		Common stock, $5 par value per share, held by Ameren Corporation – 102,123,834
Ameren Illinois Company		Common stock, no par value, held by Ameren Corporation – 25,452,373

______________________________________________________________________________________________________

This combined Form 10-Q is separately filed by Ameren Corporation, Union Electric Company, and Ameren Illinois Company. Each registrant hereto is filing on its own behalf all of the information contained in this quarterly report that relates to such registrant. Each registrant hereto is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

TABLE OF CONTENTS



		Page
Glossary of Terms and Abbreviations		1

Forward-looking Statements		1

PART I Financial Information

Item 1.	Financial Statements (Unaudited)	3
	Ameren Corporation	3
	Consolidated Statement of Income	3
	Consolidated Statement of Comprehensive Income	4
	Consolidated Balance Sheet	5
	Consolidated Statement of Cash Flows	6
	Union Electric Company (d/b/a Ameren Missouri)	7
	Statement of Income and Comprehensive Income	7
	Balance Sheet	8
	Statement of Cash Flows	9
	Ameren Illinois Company (d/b/a Ameren Illinois)	10
	Statement of Income and Comprehensive Income	10
	Balance Sheet	11
	Statement of Cash Flows	12
	Note 1. Summary of Significant Accounting Policies	13
	Note 2. Rate and Regulatory Matters	16
	Note 3. Short-term Debt and Liquidity	18
	Note 4. Long-term Debt and Equity Financings	19
	Note 5. Other Income and Expenses	20
	Note 6. Derivative Financial Instruments	20
	Note 7. Fair Value Measurements	23
	Note 8. Related Party Transactions	28
	Note 9. Commitments and Contingencies	29
	Note 10. Callaway Energy Center	32
	Note 11. Retirement Benefits	34
	Note 12. Segment Information	34
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	62
Item 4.	Controls and Procedures	64

PART II Other Information

Item 1.	Legal Proceedings	64
Item 1A.	Risk Factors	64
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	65
Item 6.	Exhibits	65

Signatures		66

GLOSSARY OF TERMS AND ABBREVIATIONS

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

EMANI – European Mutual Association for Nuclear Insurance.

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

Westinghouse – Westinghouse Electric Company, LLC.

Zero-emission credit – A credit that represents the environmental attributes of one MWh of energy produced from certain zero-emissions nuclear-powered generating facilities, which Illinois utilities are required to purchase pursuant to the FEJA.

FORWARD-LOOKING STATEMENTS

Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed under Risk Factors in the Form 10-K and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:

•

regulatory, judicial, or legislative actions, including any changes in regulatory policies and ratemaking determinations, such as those that may result from the complaint case filed in February 2015 with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff, Ameren Illinois’ April 2017 annual electric distribution formula rate update filing, and future regulatory, judicial, or legislative actions that change regulatory recovery mechanisms;


•	the effect of Ameren Illinois participating in a performance-based formula ratemaking process under the IEIMA, including the direct relationship between Ameren Illinois' return on common equity and 30-year United States Treasury bond yields, and the related financial commitments;


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


•	the effects of changes in federal, state, or local tax laws, regulations, interpretations, or rates, such as the July 2017 change in Illinois law that increased the state’s corporate income tax rate, or changes to federal tax laws as a result of tax reform legislation currently being developed by Congress, and any challenges to the tax positions taken by the Ameren Companies;


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


•	the effectiveness of Ameren Missouri's customer energy efficiency programs and the related revenues and performance incentives earned under its MEEIA plans;


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


•	our ability to align overall spending, both operating and capital, with frameworks established by our regulators and to recover these costs in a timely manner in our attempt to earn our allowed returns on equity;

•

the cost and availability of fuel, such as ultra-low-sulfur coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power, zero-emission credits, renewable energy credits, and natural gas for distribution; and the level and volatility of future market prices for such commodities, including our ability to recover the costs for such commodities and our customers' tolerance for the related rate increases;


•	disruptions in the delivery of fuel, failure of our fuel suppliers to provide adequate quantities or quality of fuel, or lack of adequate inventories of fuel, including nuclear fuel assemblies from Westinghouse, Callaway’s only NRC-licensed supplier of such assemblies, which is currently in bankruptcy proceedings;


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


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


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


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


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


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


•	the impact of weather conditions 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, as well as potential wind and solar generation projects, our ability to obtain all of the necessary approvals to complete the projects, and the uncertainty as to whether we will achieve our expected returns in a timely manner;


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


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

•

the impact of current environmental regulations and new, more stringent, or changing requirements, including those related to CO₂, other emissions and discharges, cooling water intake structures, CCR, and energy efficiency, that are enacted over time and that could limit or terminate the operation of certain of Ameren Missouri’s energy centers, increase our costs or investment requirements, result in an impairment of our assets, cause us to sell our assets, reduce our customers' demand for electricity or natural gas, or otherwise have a negative financial effect;


•	the impact of complying with renewable energy portfolio requirements in Missouri;


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


•	the inability of our counterparties to meet their obligations with respect to contracts, credit agreements, and financial instruments;


•	the cost and availability of transmission capacity for the energy generated by Ameren Missouri's energy centers or required to satisfy Ameren Missouri's energy sales;


•	legal and administrative proceedings;


•	the impact of cyber-attacks, which could, among other things, result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the loss of data, such as customer, employee, financial, and operating system information; and


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

New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement. Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF INCOME

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Operating Revenues:
Electric	$	1,594	$	1,725	$	4,183	$	4,101
Natural gas	129		134		592		619
Total operating revenues	1,723		1,859		4,775		4,720
Operating Expenses:
Fuel	199		205		594		574
Purchased power	162		178		491		451
Natural gas purchased for resale	25		34		196		227
Other operations and maintenance	402		411		1,229		1,246
Depreciation and amortization	225		211		668		628
Taxes other than income taxes	129		129		364		358
Total operating expenses	1,142		1,168		3,542		3,484
Operating Income	581		691		1,233		1,236
Other Income and Expenses:
Miscellaneous income	13		18		42		54
Miscellaneous expense	2		8		16		21
Total other income	11		10		26		33
Interest Charges	97		97		295		287
Income Before Income Taxes	495		604		964		982
Income Taxes	205		233		376		356
Net Income	290		371		588		626
Less: Net Income Attributable to Noncontrolling Interests	2		2		5		5
Net Income Attributable to Ameren Common Shareholders	$	288	$	369	$	583	$	621

Earnings per Common Share – Basic	$	1.19	$	1.52	$	2.40	$	2.56

Earnings per Common Share – Diluted	$	1.18	$	1.52	$	2.39	$	2.56

Dividends per Common Share	$	0.44	$	0.425	$	1.32	$	1.275
Average Common Shares Outstanding – Basic	242.6		242.6		242.6		242.6
Average Common Shares Outstanding – Diluted	244.7		242.9		244.0		243.0

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 September 30,					Nine Months Ended September 30,
	2017		2016			2017		2016
Net Income	$	290	$	371		$	588	$	626
Other Comprehensive Income (Loss), Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes of $-, $-, $1 and $4, respectively	—		(1		)	2		1
Comprehensive Income	290		370			590		627
Less: Comprehensive Income Attributable to Noncontrolling Interests	2		2			5		5
Comprehensive Income Attributable to Ameren Common Shareholders	$	288	$	368		$	585	$	622

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

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

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



	September 30, 2017			December 31, 2016
ASSETS
Current Assets:
Cash and cash equivalents	$	9		$	9
Accounts receivable – trade (less allowance for doubtful accounts of $20 and $19, respectively)	507			437
Unbilled revenue	262			295
Miscellaneous accounts receivable	85			63
Inventories	547			527
Current regulatory assets	75			149
Other current assets	96			113
Total current assets	1,581			1,593
Property, Plant, and Equipment, Net	20,906			20,113
Investments and Other Assets:
Nuclear decommissioning trust fund	672			607
Goodwill	411			411
Regulatory assets	1,509			1,437
Other assets	538			538
Total investments and other assets	3,130			2,993
TOTAL ASSETS	$	25,617		$	24,699
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	777		$	681
Short-term debt	446			558
Accounts and wages payable	548			805
Taxes accrued	159			46
Interest accrued	106			93
Customer deposits	108			107
Current regulatory liabilities	119			110
Other current liabilities	318			274
Total current liabilities	2,581			2,674
Long-term Debt, Net	6,922			6,595
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	4,721			4,264
Accumulated deferred investment tax credits	50			55
Regulatory liabilities	2,045			1,985
Asset retirement obligations	631			635
Pension and other postretirement benefits	711			769
Other deferred credits and liabilities	469			477
Total deferred credits and other liabilities	8,627			8,185
Commitments and Contingencies (Notes 2, 9, and 10)
Ameren Corporation Shareholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – 242.6 shares outstanding	2			2
Other paid-in capital, principally premium on common stock	5,534			5,556
Retained earnings	1,830			1,568
Accumulated other comprehensive loss	(21		)	(23		)
Total Ameren Corporation shareholders’ equity	7,345			7,103
Noncontrolling Interests	142			142
Total equity	7,487			7,245
TOTAL LIABILITIES AND EQUITY	$	25,617		$	24,699

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



AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Nine Months Ended September 30,
	2017			2016
Cash Flows From Operating Activities:
Net income	$	588		$	626
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	653			625
Amortization of nuclear fuel	71			63
Amortization of debt issuance costs and premium/discounts	16			17
Deferred income taxes and investment tax credits, net	366			364
Allowance for equity funds used during construction	(16		)	(20		)
Share-based compensation costs	12			17
Other	(7		)	(9		)
Changes in assets and liabilities:
Receivables	(59		)	(134		)
Inventories	(20		)	(13		)
Accounts and wages payable	(183		)	(196		)
Taxes accrued	138			119
Regulatory assets and liabilities	89			146
Assets, other	14			9
Liabilities, other	12			(29		)
Pension and other postretirement benefits	(31		)	(26		)
Net cash provided by operating activities	1,643			1,559
Cash Flows From Investing Activities:
Capital expenditures	(1,523		)	(1,496		)
Nuclear fuel expenditures	(52		)	(41		)
Purchases of securities – nuclear decommissioning trust fund	(248		)	(310		)
Sales and maturities of securities – nuclear decommissioning trust fund	235			297
Other	3			(1		)
Net cash used in investing activities	(1,585		)	(1,551		)
Cash Flows From Financing Activities:
Dividends on common stock	(320		)	(309		)
Dividends paid to noncontrolling interest holders	(5		)	(5		)
Short-term debt, net	(112		)	307
Maturities of long-term debt	(425		)	(389		)
Issuances of long-term debt	849			149
Share-based payments	(39		)	(32		)
Debt issuance costs	(5		)	(1		)
Other	(1		)	(2		)
Net cash used in financing activities	(58		)	(282		)
Net change in cash and cash equivalents	—			(274		)
Cash and cash equivalents at beginning of year	9			292
Cash and cash equivalents at end of period	$	9		$	18

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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Operating Revenues:
Electric	$	1,098	$	1,144	$	2,757	$	2,682
Natural gas	17		20		83		90
Other	—		1		—		1
Total operating revenues	1,115		1,165		2,840		2,773
Operating Expenses:
Fuel	199		205		594		574
Purchased power	42		77		201		169
Natural gas purchased for resale	4		6		29		33
Other operations and maintenance	224		220		655		670
Depreciation and amortization	134		130		399		384
Taxes other than income taxes	95		96		255		252
Total operating expenses	698		734		2,133		2,082
Operating Income	417		431		707		691
Other Income and Expenses:
Miscellaneous income	13		14		36		38
Miscellaneous expense	2		2		6		6
Total other income	11		12		30		32
Interest Charges	50		53		157		158
Income Before Income Taxes	378		390		580		565
Income Taxes	143		148		218		215
Net Income	235		242		362		350
Other Comprehensive Income	—		—		—		—
Comprehensive Income	$	235	$	242	$	362	$	350


Net Income	$	235	$	242	$	362	$	350
Preferred Stock Dividends	1		1		3		3
Net Income Available to Common Shareholder	$	234	$	241	$	359	$	347

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)



	September 30, 2017		December 31, 2016
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	—
Advances to money pool	18		161
Accounts receivable – trade (less allowance for doubtful accounts of $8 and $7, respectively)	274		187
Accounts receivable – affiliates	14		12
Unbilled revenue	151		154
Miscellaneous accounts receivable	45		14
Inventories	396		392
Current regulatory assets	23		35
Other current assets	43		49
Total current assets	964		1,004
Property, Plant, and Equipment, Net	11,538		11,478
Investments and Other Assets:
Nuclear decommissioning trust fund	672		607
Regulatory assets	576		619
Other assets	318		327
Total investments and other assets	1,566		1,553
TOTAL ASSETS	$	14,068	$	14,035
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	383	$	431
Accounts and wages payable	226		444
Accounts payable – affiliates	102		68
Taxes accrued	148		30
Interest accrued	61		54
Current regulatory liabilities	18		12
Other current liabilities	118		123
Total current liabilities	1,056		1,162
Long-term Debt, Net	3,584		3,563
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	3,073		3,013
Accumulated deferred investment tax credits	49		53
Regulatory liabilities	1,275		1,215
Asset retirement obligations	627		629
Pension and other postretirement benefits	274		291
Other deferred credits and liabilities	13		19
Total deferred credits and other liabilities	5,311		5,220
Commitments and Contingencies (Notes 2, 8, 9, and 10)
Shareholders’ Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding	511		511
Other paid-in capital, principally premium on common stock	1,828		1,828
Preferred stock	80		80
Retained earnings	1,698		1,671
Total shareholders’ equity	4,117		4,090
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	14,068	$	14,035

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)



	Nine Months Ended September 30,
	2017			2016
Cash Flows From Operating Activities:
Net income	$	362		$	350
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	384			381
Amortization of nuclear fuel	71			63
Amortization of debt issuance costs and premium/discounts	5			5
Deferred income taxes and investment tax credits, net	55			159
Allowance for equity funds used during construction	(15		)	(16		)
Other	4			—
Changes in assets and liabilities:
Receivables	(117		)	(95		)
Inventories	(3		)	(5		)
Accounts and wages payable	(151		)	(176		)
Taxes accrued	160			165
Regulatory assets and liabilities	48			60
Assets, other	19			(8		)
Liabilities, other	4			13
Pension and other postretirement benefits	(7		)	(8		)
Net cash provided by operating activities	819			888
Cash Flows From Investing Activities:
Capital expenditures	(533		)	(500		)
Nuclear fuel expenditures	(52		)	(41		)
Purchases of securities – nuclear decommissioning trust fund	(248		)	(310		)
Sales and maturities of securities – nuclear decommissioning trust fund	235			297
Money pool advances, net	143			(165		)
Other	—			(5		)
Net cash used in investing activities	(455		)	(724		)
Cash Flows From Financing Activities:
Dividends on common stock	(332		)	(285		)
Dividends on preferred stock	(3		)	(3		)
Maturities of long-term debt	(425		)	(260		)
Issuances of long-term debt	399			149
Capital contribution from parent	—			38
Debt issuance costs	(3		)	(1		)
Net cash used in financing activities	(364		)	(362		)
Net change in cash and cash equivalents	—			(198		)
Cash and cash equivalents at beginning of year	—			199
Cash and cash equivalents at end of period	$	—		$	1

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 September 30,					Nine Months Ended September 30,
	2017		2016			2017			2016
Operating Revenues:
Electric	$	463	$	562		$	1,343		$	1,365
Natural gas	112		114			510			530
Other	—		—			1			—
Total operating revenues	575		676			1,854			1,895
Operating Expenses:
Purchased power	124		110			312			304
Natural gas purchased for resale	21		28			167			194
Other operations and maintenance	183		198			590			592
Depreciation and amortization	86		80			254			237
Taxes other than income taxes	33		30			101			98
Total operating expenses	447		446			1,424			1,425
Operating Income	128		230			430			470
Other Income and Expenses:
Miscellaneous income	1		4			7			15
Miscellaneous expense	—		3			8			11
Total other income (expense)	1		1			(1		)	4
Interest Charges	36		35			109			105
Income Before Income Taxes	93		196			320			369
Income Taxes	38		77			127			144
Net Income	55		119			193			225
Other Comprehensive Loss, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $-, $(1), $- and $(2), respectively	—		(1		)	—			(3		)
Comprehensive Income	$	55	$	118		$	193		$	222


Net Income	$	55	$	119		$	193		$	225
Preferred Stock Dividends	—		—			2			2
Net Income Available to Common Shareholder	$	55	$	119		$	191		$	223

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)



	September 30, 2017		December 31, 2016
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	—
Accounts receivable – trade (less allowance for doubtful accounts of $12 and $12, respectively)	219		242
Accounts receivable – affiliates	21		10
Unbilled revenue	111		141
Miscellaneous accounts receivable	31		22
Inventories	151		135
Current regulatory assets	51		108
Other current assets	18		25
Total current assets	602		683
Property, Plant, and Equipment, Net	7,987		7,469
Investments and Other Assets:
Goodwill	411		411
Regulatory assets	921		816
Other assets	101		95
Total investments and other assets	1,433		1,322
TOTAL ASSETS	$	10,022	$	9,474
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	394	$	250
Short-term debt	169		51
Borrowings from money pool	11		—
Accounts and wages payable	247		264
Accounts payable – affiliates	50		63
Taxes accrued	8		16
Interest accrued	37		33
Customer deposits	69		69
Current environmental remediation	43		38
Current regulatory liabilities	85		78
Other current liabilities	153		109
Total current liabilities	1,266		971
Long-term Debt, Net	2,196		2,338
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,874		1,631
Accumulated deferred investment tax credits	1		2
Regulatory liabilities	766		768
Pension and other postretirement benefits	322		346
Environmental remediation	143		162
Other deferred credits and liabilities	229		222
Total deferred credits and other liabilities	3,335		3,131
Commitments and Contingencies (Notes 2, 8, and 9)
Shareholders’ Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding	—		—
Other paid-in capital	2,005		2,005
Preferred stock	62		62
Retained earnings	1,158		967
Total shareholders’ equity	3,225		3,034
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	10,022	$	9,474

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)



	Nine Months Ended September 30,
	2017			2016
Cash Flows From Operating Activities:
Net income	$	193		$	225
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	254			236
Amortization of debt issuance costs and premium/discounts	10			11
Deferred income taxes and investment tax credits, net	161			141
Other	(1		)	(8		)
Changes in assets and liabilities:
Receivables	59			(36		)
Inventories	(17		)	(8		)
Accounts and wages payable	(24		)	(17		)
Taxes accrued	(22		)	5
Regulatory assets and liabilities	45			75
Assets, other	(9		)	11
Liabilities, other	(2		)	6
Pension and other postretirement benefits	(19		)	(14		)
Net cash provided by operating activities	628			627
Cash Flows From Investing Activities:
Capital expenditures	(760		)	(683		)
Other	6			4
Net cash used in investing activities	(754		)	(679		)
Cash Flows From Financing Activities:
Dividends on common stock	—			(95		)
Dividends on preferred stock	(2		)	(2		)
Short-term debt, net	118			157
Money pool borrowings, net	11			54
Maturities of long-term debt	—			(129		)
Other	(1		)	(1		)
Net cash provided by (used in) financing activities	126			(16		)
Net change in cash and cash equivalents	—			(68		)
Cash and cash equivalents at beginning of year	—			71
Cash and cash equivalents at end of period	$	—		$	3

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

AMEREN CORPORATION (Consolidated)

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

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

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

September 30, 2017

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company whose primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries, Ameren Missouri, Ameren Illinois, and ATXI, are described below. Ameren also has other subsidiaries that conduct other activities, such as the provision of shared services. Ameren 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.

Ameren’s financial statements are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All intercompany transactions have been eliminated. Ameren Missouri and Ameren Illinois have no subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.

As of September 30, 2017 and December 31, 2016, Ameren had unconsolidated variable interests as a limited partner in various equity method investments, totaling $14 million and $9 million, respectively, included in “Other assets” on Ameren’s consolidated balance sheet. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly impact the activities of these variable interest entities. As of September 30, 2017, the maximum exposure to loss related to these variable interests is limited to the investment in these partnerships of $14 million plus associated outstanding funding commitments of $23 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 of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. See Note 2 – Rate and Regulatory Matters for information regarding the 2017 change in Ameren Illinois' method used to recognize interim period revenue in connection with the revenue decoupling provisions of the FEJA. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

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

Asset Retirement Obligations

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the nine months ended September 30, 2017:



	Ameren Missouri				Ameren Illinois^(a)			Ameren
Balance at December 31, 2016	$	644		^(b)	$	6		$	650		^(b)
Liabilities settled	(4		)		(1		)	(5		)
Accretion^(c)	20				(d)			20
Change in estimates^(e)	(18		)		(1		)	(19		)
Balance at September 30, 2017	$	642		^(b)	$	4		$	646		^(b)


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


(b)	Balance included $15 million in “Other current liabilities” on the balance sheet as of both December 31, 2016 and September 30, 2017, respectively.


(c)	Accretion expense was recorded as a decrease to regulatory liabilities.


(d)	Less than $1 million.


(e)	Ameren Missouri changed its fair value estimate primarily due to an extension of the remediation period of certain CCR storage facilities, an update to the decommissioning of the Callaway energy center to reflect the cost study and funding analysis filed with the MoPSC in 2017, and an increase in the discount rate assumption.

Share-based Compensation

A summary of nonvested performance share units at September 30, 2017, and changes during the nine months ended September 30, 2017, under the 2014 Incentive Plan are presented below:



	Performance Share Units
	Share Units		Weighted-average Fair Value per Share Unit
Nonvested at January 1, 2017	1,059,639		$	48.04
Granted^(a)	500,943		59.16
Forfeitures	(48,661	)	52.54
Vested^(b)	(27,446	)	52.88
Nonvested at September 30, 2017	1,484,475		$	51.55


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


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

The fair value of each performance share unit awarded in 2017 under the 2014 Incentive Plan was determined to be $59.16, which was based on Ameren’s closing common share price of $52.46 at December 31, 2016, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period beginning January 1, 2017, relative to the designated peer group. The simulations can produce a greater fair value for the performance share unit than the December 31 applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.47%, volatility of 15% to 21% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.

Operating Revenue

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

Excise Taxes

Ameren Missouri and Ameren Illinois collect certain excise taxes from customers that are levied on the sale or distribution of natural gas and electricity. Excise taxes are levied on Ameren Missouri’s electric and natural gas businesses and on Ameren Illinois’ natural gas business and are recorded gross in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” on the statement of income or the statement of income and comprehensive income. Excise taxes for electric service in Illinois are levied on the customer and therefore are not included in Ameren Illinois’ revenues and expenses. The following table presents

excise taxes recorded in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” for the three and nine months ended September 30, 2017 and 2016:



	Three Months				Nine Months
	2017		2016		2017		2016
Ameren Missouri	$	51	$	52	$	122	$	122
Ameren Illinois	10		9		40		40
Ameren	$	61	$	61	$	162	$	162

Earnings Per Share

Basic earnings per share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of common shares outstanding during the period. Earnings per diluted share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of diluted common shares outstanding during the period. Earnings per diluted share reflects the dilution that would occur if certain stock-based performance share units were settled. The number of performance share units assumed to be settled was 2.1 million and 1.4 million in the three and nine months ended September 30, 2017, respectively, and 0.3 million and 0.4 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 nine months ended September 30, 2017 and 2016.

Income Taxes

In July 2017, Illinois enacted a law that increased the state's corporate income tax rate from 7.75% to 9.5% as of July 1, 2017. The law made the increase in the state’s corporate income tax rate, which was previously scheduled to decrease to 7.3% in 2025, permanent. In July 2017, Ameren recorded 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 expense, 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 the Ameren Illinois Electric Distribution, the Ameren Transmission, or the 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 were revalued using the state’s new corporate income tax rate, which resulted in a net increase to the liability balances of $97 million and $79 million, respectively. These increased liabilities were offset by a regulatory asset, as well as income tax expense, as discussed above.

Accounting and Reporting Developments

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

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The underlying principle of the guidance is that an entity will recognize revenue for the transfer of promised goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance requires additional disclosures to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, as well as separate presentation of alternative revenue programs 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 will finalize our contract assessments by the end of 2017. We will apply the guidance using the full retrospective method and include disaggregated revenue disclosures by segment and customer class in the combined notes to the financial statements in the first quarter of 2018.

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 period and 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.

This change in the capitalization of net benefit costs will not affect our ability to continue to obtain recovery of net benefit costs through customer rates. See Note 11 – Retirement Benefits for the components of net benefit cost. This guidance will be effective for the Ameren Companies in the first quarter of 2018. We are currently assessing the impacts of this guidance on our results of operations, financial position, and disclosures.

NOTE 2 – RATE AND REGULATORY MATTERS

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

Missouri

March 2017 Electric Rate Order

The order authorized the continued use of the FAC and the regulatory tracking mechanisms for pension and postretirement benefits, uncertain income tax positions, and renewable energy standards that the MoPSC authorized in earlier electric rate orders. These regulatory tracking mechanisms provide for a base level of expense to be reflected in Ameren Missouri’s base electric rates with differences in the actual expenses incurred recorded as a regulatory asset or liability. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs 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 the third quarter of 2017, ATXI finalized an alternative project route and reached agreements with a cooperative electric company in northeast Missouri and Ameren Missouri to locate nearly all of the Mark Twain project on existing transmission line corridors. It also received assents for road crossings from the five affected counties in northeast Missouri. ATXI had previously filed suit in the circuit courts to obtain assents for the original project route. ATXI has since withdrawn one of the lawsuits. The other lawsuits remain pending but have been stayed until the first quarter of 2018. In September 2017, ATXI filed for a certificate of convenience and necessity with the MoPSC and anticipates a decision from the MoPSC in the first half of 2018. ATXI plans to complete the project in December 2019; however, delays in obtaining approval from the MoPSC could delay completion.

Illinois

IEIMA & FEJA

Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs and allowed return on equity under a formula ratemaking process effective through 2022. This formula ratemaking framework qualifies as an alternative revenue program under GAAP. Each year, Ameren Illinois records a regulatory asset or a regulatory liability and a corresponding increase or decrease to operating revenues for any differences between the revenue requirement reflected in customer rates for that year and its estimate of the probable increase or decrease in the revenue requirement expected to ultimately be approved by the ICC based on that year's actual recoverable costs incurred and investment return. As of September 30, 2017, Ameren Illinois had recorded regulatory assets of $24 million to reflect its 2016 revenue requirement reconciliation adjustment, which was included in the April 2017 formula rate update discussed below, and $16 million for the approved 2015 revenue requirement reconciliation adjustment, each with interest. As of September 30, 2017, Ameren Illinois had recorded a regulatory liability of $1 million to reflect the difference between Ameren Illinois’ estimate of its 2017 revenue requirement and the revenue requirement reflected in customer rates, including interest.

In April 2017, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for 2018 rates. In June 2017, 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. Pending ICC approval, this update filing will result in a $17 million decrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2018. This update reflects an increase to the annual formula rate based on 2016 actual costs and expected net plant additions for 2017, 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. In November 2017, an administrative law judge issued a proposed order that was consistent with Ameren Illinois’ revised July 2017 filing. An ICC decision regarding the revenue requirement to be used for customer rates in 2018 is expected by December 2017.

The FEJA revised certain portions of the IEIMA, including extending the IEIMA formula ratemaking process through 2022 and clarifying that a common equity ratio of up to, and including, 50% is prudent. Beginning in 2017, the FEJA provides that Ameren Illinois will recover, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes. Prior to the FEJA, Ameren Illinois’ interim period revenue recognition was volume-based, as revenues were affected by the timing of sales volumes due to seasonal rates and changes in volumes resulting from, among other things, weather and energy efficiency. This previous revenue recognition method resulted in more revenues during the third quarter and less revenues during the other quarters of each year. Beginning in 2017, in connection with the decoupling provisions of the FEJA, Ameren Illinois changed its method used to recognize interim period revenue. Ameren Illinois 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 a reduction to electric revenue to reflect the difference between the estimate of its revenue requirement and the revenue requirement reflected in customer rates of $76 million and $1 million for the three and nine months ended September 30, 2017, respectively. Comparative electric revenues at Ameren Illinois for the three and nine months ended September 30, 2016, were increased $11 million and $24 million, respectively, for the difference between the estimate of its revenue requirement and the revenue requirement reflected in customer rates.

In June 2017, pursuant to the FEJA, Ameren Illinois filed with the ICC an energy efficiency plan for 2018 through 2021. In September 2017, the ICC issued an order approving Ameren Illinois' implementation of FEJA electric energy efficiency savings targets and investments. Ameren Illinois plans to invest up to $99 million in electric energy efficiency programs per year from 2018 through 2021 that will earn a return. The electric energy efficiency program investments and the return on those investments will be collected from customers through a rider and will not be included in the IEIMA formula ratemaking process.

ATXI’s Illinois Rivers Project

In August 2017, the Illinois Circuit Court for Edgar County dismissed several of ATXI’s condemnation cases related to one segment in the Illinois Rivers project, which has an estimated segment cost of approximately $85 million, of which $32 million was invested as of September 30, 2017. These cases had been filed in order to obtain necessary easements and rights of way to complete the segment. The court found that required notice was not given to the relevant landowners during the underlying ICC proceeding. ATXI intends to appeal this decision. ATXI plans to complete the project in 2019; however, delays associated with the condemnation proceedings or an appeal arising from the order dismissing the Edgar County cases could delay the completion date. The other eight segments of the Illinois Rivers project are not affected by these proceedings.

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. In 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 rates since September 2016. The 10.82% allowed return on common equity may be replaced prospectively after the FERC issues a final order in the February 2015 complaint case, discussed below.

Since the maximum FERC-allowed refund period for the November 2013 complaint case ended in February 2015, another customer complaint case was filed in February 2015. MISO transmission owners have since filed a motion to dismiss the February 2015 complaint. See below for additional information about the motion. 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 approved by the FERC, would lower the allowed base return on common equity for the 15-month period of February 2015 to May 2016 to 9.70%, or a 10.20% total allowed return on equity with the inclusion of a 50 basis point incentive adder for participation in an RTO, and require customer refunds, with interest, for that 15-month period. The timing of the issuance of the final order in the February 2015 complaint case is uncertain for two reasons. First, while the FERC reestablished a quorum of commissioners in August 2017 after six months without a quorum, the FERC is 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. 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.

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 being an unjust and unreasonable return and is not applicable given the currently effective 10.32% allowed base return on common equity. The MISO transmission owners further maintain that the currently effective 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 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 is insufficient. That same approach was rejected by the United States Court of Appeals for the District of Columbia Circuit, as discussed above. FERC is under no deadline to issue an order on this motion.

As of September 30, 2017, Ameren and Ameren Illinois had recorded current regulatory liabilities of $41 million and $24 million, respectively, to reflect the expected refunds, including interest, associated with the reduced allowed returns on common equity in the initial decision in the February 2015 complaint case. Ameren Missouri does not expect that a reduction in the FERC-allowed base return on common equity would be material to its results of operations, financial position, or liquidity.

NOTE 3 – SHORT-TERM DEBT AND LIQUIDITY

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

The Missouri Credit Agreement and the Illinois Credit Agreement, both of which expire in December 2021, were not utilized for direct borrowings during the nine months ended September 30, 2017, but were used to support commercial paper issuances and to issue letters of credit. Based on commercial paper outstanding, as well as letters of credit issued under the Credit Agreements, the aggregate amount of credit capacity available under the Credit Agreements to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, at September 30, 2017, was $1.7 billion. The Ameren Companies were in compliance with the covenants in their Credit Agreements as of September 30, 2017. As of September 30, 2017, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the provisions of the Credit Agreements, were 51%, 47%, and 46% for Ameren, Ameren Missouri, and Ameren Illinois, respectively.

Commercial Paper

The following table presents commercial paper outstanding as of September 30, 2017, and December 31, 2016:



	2017		2016
Ameren (parent)	$	277	$	507
Ameren Missouri	—		—
Ameren Illinois	169		51
Ameren Consolidated	$	446	$	558

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



	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated
2017
Average daily commercial paper outstanding	$	669		$	7		$	78		$	754
Weighted-average interest rate	1.27		%	1.20		%	1.28		%	1.27		%
Peak commercial paper during period^(a)	$	841		$	64		$	193		$	948
Peak interest rate	1.50		%	1.41		%	1.50		%	1.50		%
2016
Average daily commercial paper outstanding	$	435		$	80		$	48		$	563
Weighted-average interest rate	0.81		%	0.74		%	0.72		%	0.79		%
Peak commercial paper during period^(a)	$	574		$	208		$	195		$	839
Peak interest rate	0.95		%	0.85		%	0.85		%	0.95		%


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

Money Pools

Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for short-term cash and working capital requirements. The average interest rate for borrowing under the utility money pool for the three and nine months ended September 30, 2017, was 1.24% and 1.18%, respectively (2016 – 0.53% and 0.54%, respectively). See Note 8 – Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three and nine months ended September 30, 2017 and 2016.

NOTE 4 – LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren Missouri

In June 2017, Ameren Missouri issued $400 million principal amount of 2.95% senior secured notes, due June 2027, with interest payable semiannually on June 15 and December 15 of each year, beginning in December 2017. Ameren Missouri received proceeds of $396 million, which were used, in conjunction with other available funds, to repay at maturity in June 2017 $425 million principal amount of its 6.40% 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 the remaining $300 million principal amount of the notes in August 2017. ATXI received proceeds of $449 million from the notes, which were 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. The following table presents the principal maturities schedule for the 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.

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 September 30, 2017, the Ameren Companies were in compliance with the provisions and covenants contained in their indentures and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement.

Off-Balance-Sheet Arrangements

At September 30, 2017, none of the Ameren Companies had off-balance-sheet financing arrangements, other than operating leases

entered into in the ordinary course of business, letters of credit, and Ameren parent guarantee arrangements on behalf of its subsidiaries.

NOTE 5 – OTHER INCOME AND EXPENSES

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



	Three Months				Nine Months
	2017		2016		2017		2016
Ameren:^(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	6	$	7	$	16	$	20
Interest income on industrial development revenue bonds	7		7		20		20
Interest income	—		3		5		11
Other	—		1		1		3
Total miscellaneous income	$	13	$	18	$	42	$	54
Miscellaneous expense:
Donations	$	—	$	1	$	7	$	8
Other	2		7		9		13
Total miscellaneous expense	$	2	$	8	$	16	$	21
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	6	$	6	$	15	$	16
Interest income on industrial development revenue bonds	7		7		20		20
Interest income	—		1		—		1
Other	—		—		1		1
Total miscellaneous income	$	13	$	14	$	36	$	38
Miscellaneous expense:
Donations	$	—	$	—	$	2	$	2
Other	2		2		4		4
Total miscellaneous expense	$	2	$	2	$	6	$	6
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	—	$	1	$	1	$	4
Interest income	1		2		5		9
Other	—		1		1		2
Total miscellaneous income	$	1	$	4	$	7	$	15
Miscellaneous expense:
Donations	$	—	$	1	$	5	$	6
Other	—		2		3		5
Total miscellaneous expense	$	—	$	3	$	8	$	11


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

NOTE 6 – DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives to manage the risk of changes in market prices for natural gas, power, and uranium, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. Such price fluctuations may cause the following:


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


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


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

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

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



	Quantity (in millions, except as indicated)
	2017			2016
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)^(a)	30	(b)	30	30	(b)	30
Natural gas (in mmbtu)	24	145	169	25	129	154
Power (in megawatthours)	2	9	11	1	9	10
Uranium (pounds in thousands)	370	(b)	370	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 September 30, 2017, and December 31, 2016, all contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral.

The following table presents the carrying value and balance sheet location of all derivative commodity contracts, none of which were designated as hedging instruments, as of September 30, 2017, and December 31, 2016:



	Balance Sheet Location	Ameren Missouri			Ameren Illinois		Ameren
2017
Fuel oils	Other current assets	$	2		$	—	$	2
	Other assets	1			—		1
Natural gas	Other current assets	—			1		1
	Other assets	—			1		1
Power	Other current assets	10			—		10
	Other assets	1			—		1
	Total assets ^(a)	$	14		$	2	$	16
Fuel oils	Other current liabilities	$	2		$	—	$	2
Natural gas	Other current liabilities	3			8		11
	Other deferred credits and liabilities	4			6		10
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)	$	10		$	206	$	216
2016
Fuel oils	Other current assets	$	2		$	—	$	2
	Other assets	1			—		1
Natural gas	Other current assets	1			11		12
	Other assets	1			2		3
Power	Other current assets	9			—		9
	Total assets ^(a)	$	14		$	13	$	27
Fuel oils	Other current liabilities	$	5		$	—	$	5
Natural gas	Other current liabilities	1			3		4
	Other deferred credits and liabilities	5			5		10
Power	Other current liabilities	3			12		15
	Other deferred credits and liabilities	—			173		173
Uranium	Other deferred credits and liabilities	4			—		4
	Total liabilities ^(c)	$	18		$	193	$	211


(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 September 30, 2017, and December 31, 2016.

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into groupings according to the primary business in which each engages. We calculate maximum exposures based on the

gross fair value of financial instruments, including NPNS and other accrual contracts. These exposures are calculated on a gross basis, which include affiliate exposure not eliminated at the consolidated Ameren level. As of September 30, 2017, if counterparty groups were to fail completely to perform on contracts, the Ameren Companies’ maximum exposure would have been immaterial with or without consideration of the application of master netting arrangements or similar agreements and collateral held.

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If our credit ratings were downgraded, or if a counterparty with reasonable grounds for uncertainty regarding our ability to satisfy an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of September 30, 2017, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that counterparties could require. The additional collateral required is the net liability position allowed under the master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered on September 30, 2017, and (2) those counterparties with rights to do so requested collateral.



	Aggregate Fair Value of Derivative Liabilities^(a)		Cash Collateral Posted		Potential Aggregate Amount of Additional Collateral Required^(b)
2017
Ameren Missouri	$	59	$	3	$	48
Ameren Illinois	48		—		41
Ameren	$	107	$	3	$	89


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


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

NOTE 7 – FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value.

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

The following table describes the valuation techniques and unobservable inputs utilized by the Ameren Companies for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the periods ended September 30, 2017 and December 31, 2016:



		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Weighted Average
Level 3 Derivative asset and liability – commodity contracts^(a):
2017
	Fuel oils	$	1	$	(1	)	Option model	Volatilities(%)^(b)	24 – 32	26
							Discounted cash flow	Counterparty credit risk(%)^(c)(d)	0.12 – 0.22	0.17
								Ameren Missouri credit risk(%)^(c)(d)	0.37	(e)
	Natural gas	—		(2		)	Discounted cash flow	Nodal basis ($/mmbtu)^(b)	(1.10) – (0.10)	(0.80)
								Counterparty credit risk (%)^(c)(d)	0.34 – 6	0.73
								Ameren Illinois credit risk (%)^(c)(d)	0.37	(e)
	Power^(g)	$	11	$	(193	)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(h)	25 – 41	28
								Estimated auction price for FTRs ($/MW)^(b)	(324) – 1,194	269
								Nodal basis ($/MWh)^(h)	(3) – 0	(2)



		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Weighted Average
								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 ($/mmbtu)^(b)	3 – 4	3
								Escalation rate (%)^(b)(i)	3	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/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)


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


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


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


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


(e)	Not applicable.


(f)	Escalation rate applies to fuel oil prices 2019 and beyond.


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


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


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

We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing, as well as any potential credit enhancements, into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. No gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri, or Ameren Illinois in the three and nine months ended September 30, 2017 or 2016. At September 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 assets and liabilities measured at fair value on a recurring basis as of September 30, 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	$	2	$	—	$	1	$	3
	Natural gas	1		1		—		2
	Power	—		—		11		11
	Total derivative assets – commodity contracts	$	3	$	1	$	12	$	16
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	445		—		—		445
	Debt securities:
	U.S. treasury and agency securities	—		119		—		119
	Corporate bonds	—		82		—		82
	Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	447	$	225	$	—	$	672
	Total Ameren	$	450	$	226	$	12	$	688
Ameren Missouri	Derivative assets – commodity contracts^(a):
	Fuel oils	$	2	$	—	$	1	$	3
	Power	—		—		11		11
	Total derivative assets – commodity contracts	$	2	$	—	$	12	$	14
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	445		—		—		445
	Debt securities:
	U.S. treasury and agency securities	—		119		—		119
	Corporate bonds	—		82		—		82
	Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	447	$	225	$	—	$	672
	Total Ameren Missouri	$	449	$	225	$	12	$	686
Ameren Illinois	Derivative assets – commodity contracts^(a):
	Natural gas	$	1	$	1	$	—	$	2
Liabilities:
Ameren	Derivative liabilities – commodity contracts^(a):
	Fuel oils	$	1	$	—	$	1	$	2
	Natural gas	—		19		2		21
	Power	—		—		193		193
	Total Ameren	$	1	$	19	$	196	$	216
Ameren Missouri	Derivative liabilities – commodity contracts^(a):
	Fuel oils	$	1	$	—	$	1	$	2
	Natural gas	—		7		—		7
	Power	—		—		1		1
	Total Ameren Missouri	$	1	$	7	$	2	$	10
Ameren Illinois	Derivative liabilities – commodity contracts^(a):
	Natural gas	$	—	$	12	$	2	$	14
	Power	—		—		192		192
	Total Ameren Illinois	$	—	$	12	$	194	$	206


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

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



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


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


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

All costs related to financial assets and liabilities classified as Level 3 in the fair value hierarchy are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. For the three and nine months ended September 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 September 30, 2017
Beginning balance at July 1, 2017	$	14		$	(192	)	$	(178	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(2	)		(3	)		(5	)
Sales		1			—			1
Settlements		(3	)		3			—
Ending balance at September 30, 2017	$	10		$	(192	)	$	(182	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2017	$	—		$	(2	)	$	(2	)
For the three months ended September 30, 2016
Beginning balance at July 1, 2016	$	14		$	(169	)	$	(155	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			(6	)		(6	)
Settlements		(5	)		3			(2	)
Ending balance at September 30, 2016	$	9		$	(172	)	$	(163	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2016	$	—		$	(2	)	$	(2	)
For the nine months ended September 30, 2017
Beginning balance at January 1, 2017	$	7		$	(185	)	$	(178	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(3	)		(14	)		(17	)
Purchases		15			—			15
Sales		1			—			1
Settlements		(10	)		7			(3	)
Ending balance at September 30, 2017	$	10		$	(192	)	$	(182	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2017	$	—		$	(15	)	$	(15	)
For the nine months ended September 30, 2016
Beginning balance at January 1, 2016	$	16		$	(170	)	$	(154	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(4	)		(13	)		(17	)
Purchases		13			—			13
Settlements		(16	)		11			(5	)
Ending balance at September 30, 2016	$	9		$	(172	)	$	(163	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2016	$	—		$	(7	)	$	(7	)

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 nine months ended September 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, accounts receivable, unbilled revenue, accounts payable, and other current financial instruments 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 September 30, 2017, and December 31, 2016:



	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:
Long-term debt and capital lease obligations (including current portion)	$	7,699	$	8,234	$	7,276	$	7,772
Preferred stock^(a)	142		131		142		131
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	3,967	$	4,312	$	3,994	$	4,304
Preferred stock	80		79		80		79
Ameren Illinois:
Long-term debt (including current portion)	$	2,590	$	2,759	$	2,588	$	2,765
Preferred stock	62		52		62		52


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

NOTE 8 – RELATED PARTY TRANSACTIONS

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

Electric Power Supply Agreement

In April 2017, Ameren Illinois conducted a procurement event, administered by the IPA, to purchase energy products. Ameren Missouri was among the winning suppliers in this event. As a result, in April 2017, Ameren Missouri and Ameren Illinois entered into an energy product agreement by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, 85,600 megawatthours at an average price of $34 per megawatthour during the period of March 2019 through May 2020.

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three and nine months ended September 30, 2017 and 2016:



				Three Months				Nine Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2017	$	4	$	(a)	$	21	$	(a)
agreements with Ameren Illinois		2016		9		(a)		21		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2017		7		1		20		3
rent and facility services		2016		5		1		18		3
Ameren Missouri and Ameren Illinois	Operating Revenues	2017		(b)		(b)		(b)		1
miscellaneous support services		2016		1		(b)		1		(b)
Total Operating Revenues		2017	$	11	$	1	$	41	$	4
		2016		15		1		40		3
Ameren Illinois power supply	Purchased Power	2017	$	(a)	$	4	$	(a)	$	21
agreements with Ameren Missouri		2016		(a)		9		(a)		21
Ameren Illinois transmission	Purchased Power	2017		(a)		(b)		(a)		1
services with ATXI		2016		(a)		1		(a)		2
Total Purchased Power		2017	$	(a)	$	4	$	(a)	$	22
		2016		(a)		10		(a)		23
Ameren Services support services	Other Operations and Maintenance	2017	$	34	$	33	$	103	$	99
agreement		2016		30		29		96		90
Money pool borrowings (advances)	Interest Charges/ Miscellaneous Income	2017	$	(b)	$	(b)	$	(b)	$	(b)
		2016		(b)		(b)		(b)		(b)


(a)	Not applicable.


(b)	Amount less than $1 million.

NOTE 9 – COMMITMENTS AND CONTINGENCIES

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

Reference is made to Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 14 – Related Party Transactions, and Note 15 – Commitments and Contingencies under Part II, Item 8, of the Form 10-K. See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 8 – Related Party Transactions, and Note 10 – Callaway Energy Center of this report.

Other Obligations

In April and September 2017, Ameren Illinois conducted procurement events, administered by the IPA, to purchase energy products through May 2020. In the April 2017 procurement event, Ameren Illinois contracted to purchase 4,249,800 megawatthours of energy products for $128 million from June 2017 through May 2020. In the September 2017 procurement event, Ameren Illinois contracted to purchase approximately 1,950,200 megawatthours of energy products for $57 million from October 2017 through May 2020. The results of both procurement events are reflected in the below table. See Note 8 – Related Party Transactions for additional information regarding energy product agreements between Ameren Missouri and Ameren Illinois as a result of the April procurement event.

To supply a portion of the fuel requirements of Ameren Missouri’s energy centers, Ameren Missouri has entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. Ameren Missouri and Ameren Illinois also have entered into various long-term commitments for purchased power and natural gas for distribution. The table below presents our estimated minimum fuel, purchased power, and other commitments for fuel at September 30, 2017. 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 September 30, 2017.



	Coal		Natural Gas^(a)		Nuclear Fuel		Purchased Power^(b)(c)		Methane Gas		Other		Total
Ameren:^(d)
2017	$	162	$	65	$	19	$	59	$	1	$	33	$	339
2018	453		200		67		170		4		57		951
2019	356		148		27		63		4		39		637
2020	79		94		39		13		5		39		269
2021	27		36		45		2		5		26		141
Thereafter	—		47		58		20		64		123		312
Total	$	1,077	$	590	$	255	$	327	$	83	$	317	$	2,649
Ameren Missouri:
2017	$	162	$	14	$	19	$	—	$	1	$	20	$	216
2018	453		42		67		—		4		44		610
2019	356		34		27		—		4		25		446
2020	79		26		39		—		5		25		174
2021	27		13		45		—		5		26		116
Thereafter	—		22		58		—		64		100		244
Total	$	1,077	$	151	$	255	$	—	$	83	$	240	$	1,806
Ameren Illinois:
2017	$	—	$	51	$	—	$	59	$	—	$	13	$	123
2018	—		158		—		170		—		13		341
2019	—		114		—		63		—		14		191
2020	—		68		—		13		—		14		95
2021	—		23		—		2		—		—		25
Thereafter	—		25		—		20		—		—		45
Total	$	—	$	439	$	—	$	327	$	—	$	54	$	820


(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.

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 water, water usage, impacts to air, land, and water, and chemical and waste handling. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures.

The EPA has promulgated environmental regulations that have a significant impact on the electric utility industry. Over time, compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants. As of December 31, 2016, Ameren Missouri’s fossil fuel-fired energy centers represented 18% and 34% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations impacting 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_X, mercury, toxic metals, and acid gases. Water intake and discharges from power plants are regulated under the Clean Water Act. Modifications to water intake structures and more stringent limitations or prohibitions against wastewater discharges at Ameren Missouri’s energy centers 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 individual or combined effects of existing environmental regulations could result in significant capital expenditures, increased operating costs, the closure or alteration of the operation of some of Ameren Missouri’s energy centers, or require further capital investment. Ameren and Ameren Missouri expect that such compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the timing of costs and their recovery could be subject to regulatory lag.

Ameren Missouri's current plan for compliance with existing 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 $425 million to $525 million in the aggregate from 2017 through 2021 in order to comply with existing environmental regulations. Additional environmental controls beyond 2021 could be required. This estimate of capital expenditures includes expenditures required for the CCR regulations, Clean Water Act rules applicable to cooling water intake structures at existing power plants, and effluent limitation guidelines applicable to steam electric generating units, all of which are discussed below. The EPA has proposed to repeal the Clean Power Plan, which would have regulated CO₂emissions from power plants. The above capital expenditure amounts exclude estimated impacts from the Clean Power Plan. The actual amount of capital expenditures required to comply with existing environmental regulations may vary substantially from the above estimate because of uncertainty as to whether the EPA will substantively revise regulatory obligations, the precise compliance strategies that will be used and their ultimate cost, among other things.

The following sections describe the more significant 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 rulemaking activities, including 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 SO₂and NO_x through either emission source reductions or the use and retirement of emission allowances. The first phase of the CSAPR emission reduction requirements became effective in 2015. 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 CO₂emissions standards applicable to existing power plants. In October 2017, the EPA announced a proposal to repeal the Clean Power Plan and will seek public comment as to the scope of future regulations

under the Clean Air Act. The United States Court of Appeals for the District of Columbia Circuit has stayed further action pending the EPA’s administrative review.

We cannot predict the outcome of the EPA’s future rulemaking, the outcome of legal challenges relating to either the repeal of the Clean Power Plan or such future rulemakings, nor the resulting impact on our results of operations, financial position, or liquidity.

NSR and Clean Air Litigation

In January 2011, the Department of Justice, on behalf of the EPA, filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The complaint, as amended in October 2013, alleged that in performing projects at its Rush Island coal-fired energy center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. The litigation has been divided into two phases: liability and remedy. In January 2017, the district court issued a liability ruling that the projects violated provisions of the Clean Air Act and Missouri law. The case will now proceed to the second phase to determine the actions required to remedy the violations found in the liability phase of the litigation. The EPA previously withdrew all claims for penalties and fines. 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, the EPA issued its final rule applicable to cooling water intake structures at existing power plants. The rule requires a case-by-case evaluation and plan for reducing aquatic organisms impinged on the facility’s intake screens or entrained through the plant's cooling water system. All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to the cooling water intake structures rule. Implementation of the rule will occur during the permit renewal process of each energy center’s water discharge permit, which will occur between 2018 and 2023.

Additionally, in 2015, the EPA issued a rule to revise the effluent limitation guidelines applicable to steam electric generating units. These guidelines established national standards for water discharges that are based on the effectiveness of available control technology. The EPA's 2015 rule prohibits effluent discharges of certain waste streams and imposes more stringent limitations on certain water discharges from power plants. In September 2017, the EPA published a rule that postponed the compliance dates by two years for the limitations applicable to two specific waste streams so that it could potentially revise those standards.

Both the intake and effluent rules, if implemented as enacted, could have an adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity should such implementation require extensive modifications to the cooling water systems and water discharge systems at Ameren Missouri’s energy centers, and if such investments are not recovered on a timely basis in electric rates charged to Ameren Missouri’s customers.

Ash Management

In 2015, the EPA issued regulations regarding the management and disposal of CCR from coal-fired energy centers. These regulations affect CCR disposal and handling costs at Ameren Missouri's energy centers. They require closure of impoundments if performance criteria relating to groundwater impacts and location restrictions are not achieved. In September 2017, the EPA granted petitions filed on behalf of coal-fired electricity generators in which the EPA agreed to reconsider provisions of the CCR rules. Ameren and Ameren Missouri’s AROs associated with CCR storage facilities reflect the regulations issued in 2015. Ameren plans to close these CCR storage facilities between 2018 and 2024. Ameren Missouri's capital expenditure plan includes the cost of constructing landfills as part of its environmental compliance plan.

Remediation

The Ameren Companies are involved in a number of remediation actions to clean up sites impacted by the use or disposal of materials containing hazardous substances. Federal and state laws can require responsible parties to fund remediation regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. Ameren Missouri and Ameren Illinois have each been identified by federal or state governments as a potentially responsible party at several contaminated sites.

As of September 30, 2017, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois, which are in various stages of investigation, evaluation, remediation, and closure. Ameren Illinois estimates it could substantially conclude remediation efforts by

2023. The ICC allows Ameren Illinois to recover remediation and litigation costs associated with its former MGP sites from its electric and natural gas utility customers through environmental adjustment rate riders. Costs are subject to annual review by the ICC. As of September 30, 2017, Ameren Illinois estimated the obligation related to these former MGP sites at $184 million to $255 million. Ameren and Ameren Illinois recorded a liability of $184 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate.

The scope of the remediation activities at these former MGP sites may increase as remediation efforts continue. Considerable uncertainty remains in these estimates because many site-specific factors can influence the ultimate actual costs, including unanticipated underground structures, the degree to which groundwater is encountered, regulatory changes, local ordinances, and site accessibility. The actual costs 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 the potentially responsible parties will determine how to fund the implementation of the EPA-approved remedies. As of September 30, 2017, Ameren Missouri estimated its obligation related to Sauget Area 2 at $1 million to $2.5 million. Ameren Missouri recorded a liability of $1 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate.

Our operations or those of our predecessor companies involve the use of, disposal of, and, in appropriate circumstances, the cleanup of substances regulated under environmental laws. We are unable to determine whether such practices will result in future environmental commitments or will affect our results of operations, financial position, or liquidity.

Ameren Missouri Municipal Taxes

The cities of Creve Coeur and Winchester, Missouri, on behalf of themselves and other municipalities in Ameren Missouri’s service area, filed a class action lawsuit in 2011 against Ameren Missouri in the Circuit Court of St. Louis County, Missouri. The lawsuit alleges that Ameren Missouri failed to pay gross receipts taxes or license fees on certain revenues, including revenues from wholesale power and interchange sales. In the third quarter of 2017, the court issued an order preliminarily approving a settlement between Ameren Missouri and the plaintiffs, with final resolution of the case expected in the first quarter of 2018. Ameren and Ameren Missouri recorded immaterial liabilities on their respective balance sheets as of September 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.

NOTE 10 – CALLAWAY ENERGY CENTER

Spent Nuclear Fuel

Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. The NWPA established the fee that Ameren Missouri and other utilities that own and operate those energy centers pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatthour generated and sold by those plants. The NWPA also requires the DOE to review the nuclear waste fee annually against the cost of the nuclear waste disposal program and to propose to the United States Congress any fee adjustment necessary to offset the costs of the program. As required by the NWPA, Ameren Missouri and other utilities have entered into standard contracts with the DOE. Consistent with the NWPA and its standard contract, which stated that the DOE would begin to dispose of spent nuclear fuel by 1998, Ameren Missouri had historically collected one mill from its electric customers for each kilowatthour of electricity that it generated and sold from its Callaway energy center. Because the federal government is not meeting its disposal obligation, the collection of this fee was suspended in May 2014. The DOE's delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway energy center is not expected to adversely affect the continued operations of the energy center.

As a result of the DOE's failure to fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners sued the DOE to recover costs incurred for ongoing storage of their spent fuel. The lawsuit resulted in a settlement agreement that provides for annual reimbursement of additional spent fuel storage and related costs. Ameren Missouri received reimbursements from the DOE of $3 million and $24 million in October 2017 and September 2016, respectively. Ameren Missouri will continue to apply for reimbursement from the DOE for allowable costs associated with the ongoing storage of spent fuel.

Decommissioning

Electric utility rates charged to customers provide for the recovery of the Callaway energy center's decommissioning costs, which include decontamination, dismantling, and site restoration costs, over the expected life of the nuclear energy center. Amounts collected from customers are deposited into the external nuclear decommissioning trust fund to provide for the Callaway energy center’s decommissioning. It is assumed that the Callaway energy center site will be decommissioned through the immediate dismantlement method and removed from service. Ameren and Ameren Missouri have recorded an ARO for the Callaway energy center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Annual decommissioning costs of $7 million are included in the costs used to establish electric rates for Ameren Missouri's customers. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway energy center. An updated cost study and funding analysis was filed with the MoPSC in September 2017 and reflected within the ARO. Ameren Missouri’s filing supported no change in electric service rates for decommissioning costs. There is no deadline by which the MoPSC must issue an order regarding the filing.

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

Supplier of Fuel Assemblies

Ameren Missouri received all necessary fuel assemblies for the fourth quarter 2017 refueling and maintenance outage. 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. 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 if nuclear fuel assemblies were not available for a future scheduled refueling and maintenance outage. A change of fuel suppliers or a change in the type of fuel assembly design that is currently licensed for use at the Callaway energy center could take an estimated three years of analysis and NRC licensing efforts to implement.

Insurance

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at September 30, 2017. The property coverage and the nuclear liability coverage renewal dates are April 1 and January 1, respectively, of each year. Both coverages were renewed in 2017.



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


(a)	Provided through mandatory participation in an industrywide retrospective premium assessment program.


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


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


(d)	NEIL provides $2.7 billion in property damage, stabilization, decontamination, and premature decommissioning insurance for radiation events and $2.3 billion in property damage 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

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



	Pension Benefits												Postretirement Benefits
	Three Months						Nine Months						Three Months						Nine Months
	2017			2016			2017			2016			2017			2016			2017			2016
Service cost	$	24		$	20		$	70		$	60		$	6		$	5		$	16		$	15
Interest cost	44			46			134			138			12			12			35			36
Expected return on plan assets	(65		)	(63		)	(196		)	(189		)	(19		)	(18		)	(56		)	(54		)
Amortization of:
Prior service benefit	(1		)	—			(1		)	—			(2		)	(1		)	(4		)	(3		)
Actuarial loss (gain)	14			8			41			24			(2		)	(3		)	(5		)	(8		)
Net periodic benefit cost (benefit)	$	16		$	11		$	48		$	33		$	(5	)	$	(5	)	$	(14	)	$	(14	)

Ameren Missouri and Ameren Illinois are responsible for their respective shares of Ameren’s pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs (benefit) incurred for the three and nine months ended September 30, 2017 and 2016:



	Pension Benefits										Postretirement Benefits
	Three Months					Nine Months					Three Months						Nine Months
	2017		2016			2017		2016			2017			2016			2017			2016
Ameren Missouri^(a)	$	6	$	6		$	18	$	19		$	(1	)	$	(1	)	$	(3	)	$	(3	)
Ameren Illinois	10		6			30		17			(3		)	(3		)	(10		)	(10		)
Other	—		(1		)	—		(3		)	(1		)	(1		)	(1		)	(1		)
Ameren^(a)(b)	$	16	$	11		$	48	$	33		$	(5	)	$	(5	)	$	(14	)	$	(14	)


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


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

NOTE 12 – SEGMENT INFORMATION

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

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

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

The following tables present revenues, net income attributable to common shareholders, and capital expenditures by segment at Ameren and Ameren Illinois for the three and nine months ended September 30, 2017 and 2016. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.

Ameren



Three Months	Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission			Other			Intersegment Eliminations			Consolidated
2017
External revenues	$	1,104	$	405	$	111	$	105		$	(2	)	$	—		$	1,723
Intersegment revenues	11		—		1		14		^(a)	—			(26		)	—
Net income attributable to Ameren common shareholders	234		31		2		38		^(b)	(17		)	—			288
Capital expenditures	178		112		71		173			(2		)	(7		)	525
2016
External revenues	$	1,150	$	502	$	113	$	94		$	—		$	—		$	1,859
Intersegment revenues	15		1		1		14		^(a)	—			(31		)	—
Net income attributable to Ameren common shareholders	241		93		2		39		^(b)	(6		)	—			369
Capital expenditures	147		123		50		175			1			—			496
Nine Months
2017
External revenues	$	2,799	$	1,176	$	509	$	293		$	(2	)	$	—		$	4,775
Intersegment revenues	41		3		1		33		^(a)	—			(78		)	—
Net income attributable to Ameren common shareholders	359		94		40		106		^(b)	(16		)	—			583
Capital expenditures	533		354		180		463			3			(10		)	1,523
2016
External revenues	$	2,733	$	1,210	$	529	$	247		$	1		$	—		$	4,720
Intersegment revenues	40		3		1		36		^(a)	—			(80		)	—
Net income attributable to Ameren common shareholders	347		122		44		98		^(b)	10			—			621
Capital expenditures	500		359		130		503			4			—			1,496


(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
2017
External revenues	$	405	$	112	$	58		$	—		$	575
Intersegment revenues	—		—		14		^(a)	(14		)	—
Net income available to common shareholder	31		2		22			—			55
Capital expenditures	112		71		93			—			276
2016
External revenues	$	503	$	114	$	59		$	—		$	676
Intersegment revenues	—		—		14		^(a)	(14		)	—
Net income available to common shareholder	93		2		24			—			119
Capital expenditures	123		50		68			—			241
Nine Months
2017
External revenues	$	1,179	$	510	$	165		$	—		$	1,854
Intersegment revenues	—		—		32		^(a)	(32		)	—
Net income available to common shareholder	94		40		57			—			191
Capital expenditures	354		180		226			—			760
2016
External revenues	$	1,213	$	530	$	152		$	—		$	1,895
Intersegment revenues	—		—		35		^(a)	(35		)	—
Net income available to common shareholder	122		44		57			—			223
Capital expenditures	359		130		194			—			683


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

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

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


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

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 $288 million in the three months ended September 30, 2017, compared with $369 million in the year-ago period. Net income attributable to Ameren common shareholders was $583 million in nine months ended September 30, 2017, compared with $621 million in the year-ago period. Net income was unfavorably affected in the three and nine months ended September 30, 2017, compared to the year-ago periods, by milder temperatures in 2017 and decreased Ameren Illinois Electric Distribution earnings due to 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. Earnings were also unfavorably affected in the three and nine months ended September 30, 2017, compared to the year-ago periods, by the absence of the recognition in 2016 of a MEEIA 2013 performance incentive award at Ameren Missouri. Net income in the three and nine months ended September 30, 2017, compared to the year-ago periods, was favorably affected by an increase in base rates and lower base level of tracked expense at Ameren Missouri pursuant to the MoPSC’s March 2017 electric rate order and increased investments in infrastructure at the Ameren Illinois Electric Distribution and Ameren Transmission segments reflecting Ameren’s strategy to allocate incremental capital to those businesses.

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 nine months of 2017, Ameren continued to allocate significant amounts of capital to those businesses that are supported by constructive regulatory frameworks, investing $1 billion of capital expenditures in its FERC rate-regulated electric transmission and Illinois electric and natural gas distribution businesses.

In March 2017, the MoPSC issued an order approving a unanimous stipulation and agreement in Ameren Missouri’s July 2016 regulatory rate review. The electric rate order resulted in a $92 million increase in Ameren Missouri’s revenue requirement, a $54 million decrease in the base level of net energy costs, and a $26 million reduction in the base level of certain tracked expenses, compared to the amounts in the MoPSC’s April 2015 rate order. The new rates and base level of expenses became effective on April 1, 2017. In September 2017, Ameren Missouri filed its non-binding 20-year integrated resource plan with the MoPSC, which includes Ameren Missouri’s preferred plan for meeting customers’ projected long-term energy needs in a cost-effective fashion that maintains system reliability as it targets cleaner and more diverse sources of energy generation. These new renewable energy sources would also 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. Ameren Missouri’s plan contemplates adding at least 700 megawatts of wind generation by 2020, as well as 100 megawatts of solar generation over the next 10 years, with 50 megawatts anticipated to come online by 2025. The new wind generation is expected to be located in Missouri and neighboring states. The source, location, and cost of the new wind generation, among other items, remain subject to reaching agreements with developers. 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 alternative for customers. The plan also includes expected implementation of continued customer energy efficiency programs. Ameren Missouri’s plan for the addition of renewable resources could be impacted by, among other factors: the availability of federal production tax credits related to renewable energy and its ability to use such credits; the cost of wind and solar generation technologies, as well as energy prices; Ameren Missouri’s ability to obtain 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, or any other required project approvals. The wind generation identified in Ameren Missouri’s plan could represent incremental investments of approximately $1 billion. In connection with the integrated resource plan 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 its useful life.

Ameren Illinois invested approximately $535 million in electric distribution and natural gas infrastructure projects in the first nine months of 2017. In April 2017, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for 2018 rates. In June 2017, 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. Pending ICC approval, this update filing will result in a $17 million decrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2018. This update reflects an increase to the annual formula rate based on 2016 actual costs and expected net plant additions for 2017, 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. An ICC decision on the revenue requirement to be used for 2018 rates is expected by December 2017.

In the first nine months of 2017, Ameren Transmission invested approximately $460 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 construction activities for its Illinois Rivers and Spoon River projects are continuing on schedule and are expected to be completed by 2019 and 2018, respectively. Related to its Mark Twain project, in the third quarter of 2017, ATXI finalized an alternative project route and reached agreements with a cooperative electric company in northeast Missouri and Ameren Missouri to locate nearly all of the project on existing transmission line corridors. It also received assents for road crossings from the five affected counties in northeast Missouri. ATXI filed for a certificate of convenience and necessity with the MoPSC and anticipates a decision from the MoPSC in the first half of 2018. ATXI plans to complete the project in December 2019; however, delays in obtaining approval from the MoPSC could delay completion.

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 amount of the notes in June 2017 and the remaining $300 million principal amount of the notes in August 2017. ATXI received proceeds of $449 million from the notes which were used by ATXI to repay existing short-term and long-term affiliate debt owed to Ameren (parent).

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Economic conditions, energy efficiency investments by our customers and us, and the actions of key customers can significantly affect the demand for our services. Ameren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling demands as well as by nuclear refueling and other energy center maintenance outages. Additionally, fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing and our pension and postretirement benefits costs. Almost all of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the prices we charge for our services. Our results of operations, financial position, and liquidity are affected by our ability to align our overall spending, both operating and capital, with regulatory frameworks established by our regulators.

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

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

remaining 5% of changes retained by Ameren Missouri. Net energy costs, as defined in the FAC, include fuel and purchased power costs net of off-system sales. Ameren Missouri accrues net energy costs that exceed the amount set in base rates (FAC under-recovery) as a regulatory asset. Net recovery of these costs through customer rates does not affect Ameren Missouri's electric margins, as any change in revenue is offset by a corresponding change in fuel expense to reduce the previously recognized FAC regulatory asset. See the definition of margin in the Electric and Natural Gas Margins section below. In addition, Ameren Missouri’s MEEIA customer energy efficiency program costs, throughput disincentive, and any performance incentive are recoverable through the MEEIA cost recovery mechanism without a traditional rate proceeding. 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 standards cost tracker, and a solar rebate program tracker. Each of these trackers allows Ameren Missouri to record the difference between the level of incurred costs under GAAP and the level of such costs included in rates as a regulatory asset or regulatory liability, which will be reflected in base rates in a subsequent MoPSC rate order.

Ameren Illinois’ electric distribution service business has cost recovery mechanisms for power purchased and transmission services incurred on behalf of its customers. The FEJA also provides Ameren Illinois electric distribution with cost recovery of renewable energy credit compliance, zero-emission credits, and energy efficiency investments as well as a return on those investments. Ameren Illinois’ natural gas business has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through costs do not affect Ameren Illinois' electric or natural gas margins, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois employs other cost recovery mechanisms for customer energy efficiency program costs and certain environmental costs as well as bad debt expense and costs of certain asbestos-related claims not recovered in base rates. Ameren Illinois’ natural gas business also has the QIP rider to recover the costs of qualifying infrastructure plant investments placed in service between rate cases and earn a return those investments.

Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs and allowed return on equity under a formula ratemaking process effective through 2022. These recoverable electric distribution costs include other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes. These recoverable costs do 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. If a given year's revenue requirement is greater than the revenue requirement reflected in that year's customer rates, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional amounts from customers within two years. If a given year's revenue requirement is less than the revenue requirement reflected in that year's customer rates, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within two years.

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. The return on equity 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 electric transmission formula rate framework provide 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. Ameren Illinois and ATXI use a company-specific, forward-looking rate formula framework in setting their transmission rates. These rates are updated each January with forecasted information. If a given year's revenue requirement is greater than the revenue requirement reflected in that year's customer rates, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional amounts from customers within two years. If a given year's revenue requirement is less than the revenue requirement reflected in that year's customer rates, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within two years. The total return on equity currently allowed for Ameren Illinois’ and ATXI’s electric transmission service businesses is 10.82% and is subject to a FERC complaint case. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information.

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 and nine months ended September 30, 2017 and 2016:



	Three Months				Nine Months
	2017		2016		2017		2016
Net income attributable to Ameren common shareholders	$	288	$	369	$	583	$	621
Earnings per common share – diluted	1.18		1.52		2.39		2.56

Net income attributable to Ameren common shareholders decreased $81 million, or 34 cents per diluted share, in the three months ended September 30, 2017, compared with the year-ago period. The decrease was principally due to net income decreases of $62 million and $7 million at Ameren Illinois Electric Distribution and Ameren Missouri, respectively, and an increase in net loss of $11 million for activity not reported as part of a segment, primarily at Ameren (parent).

Net income attributable to Ameren common shareholders decreased $38 million, or 17 cents per diluted share, in the nine months ended September 30, 2017, compared with the year-ago period. The decrease was due to net income decreases of $28 million and $4 million at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively. Additionally, activity not reported as part of a segment, primarily Ameren (parent), had a $16 million net loss in the first nine months of 2017, compared with net income of $10 million in the same period in 2016. The decrease was partially offset by an increase in net income of $12 million and $8 million at Ameren Missouri and Ameren Transmission, respectively.

Earnings per diluted share were unfavorably affected in the three and nine months ended September 30, 2017, compared to the year-ago periods (except where a specific period is referenced), by:


•	decreased demand primarily at Ameren Missouri due to milder winter and summer temperatures in 2017 (estimated at 8 cents per share and 16 cents per share, respectively);


•	a change in the method used to recognize Ameren Illinois Electric Distribution’s interim period revenue in connection with the decoupling provisions of the FEJA as discussed in Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report (24 cents per share and 12 cents per share, respectively);


•	an increase in income tax expense due to an increase in the Illinois corporate income tax rate recorded at Ameren (parent) as discussed in Note 1 – Summary of Significant Accounting Policies under Part I, Item 1, of this report (6 cents per share for both periods);


•	the absence in 2017 of the MEEIA 2013 performance incentive at Ameren Missouri recognized in the third quarter of 2016 (5 cents per share for both periods);


•	increased depreciation and amortization expenses, primarily at Ameren Missouri, resulting from additional electric property, plant, and equipment (2 cents per share and 5 cents per share, respectively);


•	an increase in the effective tax rate, excluding the effect of the increase in the Illinois corporate income tax rate discussed above, primarily due to a decrease in the income tax benefit recorded at Ameren (parent) related to share-based compensation (4 cents per share for the nine months ended September 30, 2017);

•

the absence of increased Ameren Missouri electric margins in 2016 resulting from the suspension of operations at the New Madrid Smelter in the first quarter of 2016 and the elimination of recovery under the FAC tariff effective April 1, 2017, which had allowed Ameren Missouri to retain a portion of the revenues from off-system sales it made as a result of reduced sales to the New Madrid Smelter as discussed in the Electric and Natural Gas Margins section below (1 cent per share and 2 cents per share, respectively); and


•	increased other operations and maintenance expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri, primarily due to increased repairs and compliance expenditures (2 cents per share for the nine months ended September 30, 2017).

Earnings per diluted share were favorably affected in the three and nine months ended September 30, 2017, compared to the year-ago periods (except where a specific period is referenced), by:


•	an increase in 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 (15 cents per share and 26 cents per share, respectively);


•	the absence in 2017 of costs associated with the Callaway energy center’s scheduled refueling and maintenance outage in the second quarter of 2016, partially offset by costs incurred to prepare for the scheduled outage that began in October 2017 (7 cents per share for the nine months ended September 30, 2017);


•	increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base partially offset by a lower recognized return on equity (1 cent per share and 5 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 (2 cents per share and 4 cents per share, respectively).

The cents per share information presented is based on the average diluted shares outstanding in the three and nine months ended September 30, 2016. Amounts have been presented net of income taxes using Ameren’s 2016 statutory tax rate of 39%. For additional details regarding the Ameren Companies’ results of operations, including explanations of Electric and Natural Gas Margins, Other Operations and Maintenance Expenses, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income and Expenses, Interest Charges, and Income Taxes, see the major headings below.

Below is Ameren’s table of income statement components by segment for the three and nine months ended September 30, 2017 and 2016:



	Ameren Missouri			Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas			Ameren Transmission			Other / Intersegment Eliminations			Total
Three Months 2017:
Electric margins	$	857		$	267		$	—		$	119		$	(10	)	$	1,233
Natural gas margins	13			—			91			—			—			104
Other operations and maintenance	(224		)	(118		)	(52		)	(16		)	8			(402		)
Depreciation and amortization	(134		)	(60		)	(15		)	(15		)	(1		)	(225		)
Taxes other than income taxes	(95		)	(20		)	(12		)	(1		)	(1		)	(129		)
Other income (expense)	11			1			—			—			(1		)	11
Interest charges	(50		)	(19		)	(8		)	(18		)	(2		)	(97		)
Income taxes	(143		)	(20		)	(2		)	(31		)	(9		)	(205		)
Net income (loss)	235			31			2			38			(16		)	290
Noncontrolling interests – preferred stock dividends	(1		)	—			—			—			(1		)	(2		)
Net income (loss) attributable to Ameren common shareholders	$	234		$	31		$	2		$	38		$	(17	)	$	288
Three Months 2016:
Electric margins	$	862		$	379		$	—		$	108		$	(7	)	$	1,342
Natural gas margins	14			—			86			—			—			100
Other revenues	1			—			—			—			(1		)	—
Other operations and maintenance	(220		)	(132		)	(52		)	(17		)	10			(411		)
Depreciation and amortization	(130		)	(57		)	(13		)	(10		)	(1		)	(211		)
Taxes other than income taxes	(96		)	(20		)	(10		)	(1		)	(2		)	(129		)
Other income (expense)	12			2			(1		)	—			(3		)	10
Interest charges	(53		)	(17		)	(8		)	(17		)	(2		)	(97		)
Income (taxes) benefit	(148		)	(62		)	—			(24		)	1			(233		)
Net income (loss)	242			93			2			39			(5		)	371
Noncontrolling interests – preferred stock dividends	(1		)	—			—			—			(1		)	(2		)
Net income (loss) attributable to Ameren common shareholders	$	241		$	93		$	2		$	39		$	(6	)	$	369
Nine Months 2017:
Electric margins	$	1,962		$	834		$	—		$	326		$	(24	)	$	3,098
Natural gas margins	54			—			343			—			(1		)	396
Other revenues	—			1			—			—			(1		)	—
Other operations and maintenance	(655		)	(391		)	(159		)	(47		)	23			(1,229		)
Depreciation and amortization	(399		)	(178		)	(44		)	(44		)	(3		)	(668		)
Taxes other than income taxes	(255		)	(56		)	(43		)	(4		)	(6		)	(364		)
Other income (expense)	30			1			(2		)	—			(3		)	26
Interest charges	(157		)	(55		)	(27		)	(49		)	(7		)	(295		)
Income (taxes) benefit	(218		)	(61		)	(27		)	(76		)	6			(376		)
Net income (loss)	362			95			41			106			(16		)	588
Noncontrolling interests – preferred dividends	(3		)	(1		)	(1		)	—			—			(5		)
Net income (loss) attributable to Ameren common shareholders	$	359		$	94		$	40		$	106		$	(16	)	$	583
Nine Months 2016:
Electric margins	$	1,939		$	874		$	—		$	283		$	(20	)	$	3,076
Natural gas margins	57			—			336			—			(1		)	392
Other revenues	1			—			—			—			(1		)	—
Other operations and maintenance	(670		)	(399		)	(153		)	(47		)	23			(1,246		)
Depreciation and amortization	(384		)	(169		)	(40		)	(30		)	(5		)	(628		)
Taxes other than income taxes	(252		)	(54		)	(42		)	(3		)	(7		)	(358		)
Other income (expense)	32			5			(2		)	1			(3		)	33
Interest charges	(158		)	(54		)	(26		)	(43		)	(6		)	(287		)
Income (taxes) benefit	(215		)	(80		)	(28		)	(63		)	30			(356		)
Net income	350			123			45			98			10			626
Noncontrolling interests – preferred dividends	(3		)	(1		)	(1		)	—			—			(5		)
Net income attributable to Ameren common shareholders	$	347		$	122		$	44		$	98		$	10		$	621

Below is Ameren Illinois' table of income statement components by segment for the three and nine months ended September 30, 2017 and 2016:



	Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas			Ameren Illinois Transmission			Total
Three Months 2017:
Electric and natural gas margins	$	267		$	91		$	72		$	430
Other operations and maintenance	(118		)	(52		)	(13		)	(183		)
Depreciation and amortization	(60		)	(15		)	(11		)	(86		)
Taxes other than income taxes	(20		)	(12		)	(1		)	(33		)
Other income	1			—			—			1
Interest charges	(19		)	(8		)	(9		)	(36		)
Income taxes	(20		)	(2		)	(16		)	(38		)
Net income	31			2			22			55
Preferred stock dividends	—			—			—			—
Net income attributable to common shareholder	$	31		$	2		$	22		$	55
Three Months 2016:
Electric and natural gas margins	$	379		$	86		$	73		$	538
Other operations and maintenance	(132		)	(52		)	(14		)	(198		)
Depreciation and amortization	(57		)	(13		)	(10		)	(80		)
Taxes other than income taxes	(20		)	(10		)	—			(30		)
Other income (expense)	2			(1		)	—			1
Interest charges	(17		)	(8		)	(10		)	(35		)
Income taxes	(62		)	—			(15		)	(77		)
Net income	93			2			24			119
Preferred stock dividends	—			—			—			—
Net income attributable to common shareholder	$	93		$	2		$	24		$	119
Nine Months 2017:
Electric and natural gas margins	$	834		$	343		$	197		$	1,374
Other revenues	1			—			—			1
Other operations and maintenance	(391		)	(159		)	(40		)	(590		)
Depreciation and amortization	(178		)	(44		)	(32		)	(254		)
Taxes other than income taxes	(56		)	(43		)	(2		)	(101		)
Other income (expense)	1			(2		)	—			(1		)
Interest charges	(55		)	(27		)	(27		)	(109		)
Income taxes	(61		)	(27		)	(39		)	(127		)
Net income	95			41			57			193
Preferred stock dividends	(1		)	(1		)	—			(2		)
Net income attributable to common shareholder	$	94		$	40		$	57		$	191
Nine Months 2016:
Electric and natural gas margins	$	874		$	336		$	187		$	1,397
Other operations and maintenance	(399		)	(153		)	(40		)	(592		)
Depreciation and amortization	(169		)	(40		)	(28		)	(237		)
Taxes other than income taxes	(54		)	(42		)	(2		)	(98		)
Other income (expense)	5			(2		)	1			4
Interest charges	(54		)	(26		)	(25		)	(105		)
Income taxes	(80		)	(28		)	(36		)	(144		)
Net income	123			45			57			225
Preferred stock dividends	(1		)	(1		)	—			(2		)
Net income attributable to common shareholder	$	122		$	44		$	57		$	223

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 nine months ended September 30, 2017, compared with the year-ago periods. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as natural gas revenues less natural gas purchased for resale. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP, and they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.



Three Months	Ameren Missouri			Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas				Ameren Transmission^(a)		Other / Intersegment Eliminations			Ameren
Electric revenue change:
Effect of weather (estimate)^(b)	$	(33	)	$	(9	)	$	—			$	—	$	—		$	(42	)
Base rates (estimate)^(c)	29			10			—				11		—			50
FEJA impact on IEIMA – timing of revenue recognition	—			(94		)	—				—		—			(94		)
Recovery of power restoration efforts provided to other utilities	5			1			—				—		—			6
Sales volume (excluding the effect of weather and the New Madrid Smelter)	8			—			—				—		—			8
New Madrid Smelter revenues	(1		)	—			—				—		—			(1		)
MEEIA 2013 performance incentive	(19		)	—			—				—		—			(19		)
Off-system sales	(38		)	—			—				—		—			(38		)
Transmission services revenues	2			—			—				—		—			2
Other	(8		)	(4		)	—				—		2			(10		)
Cost recovery mechanisms – offset in fuel and purchased power:^(d)
Power supply costs	—			(7		)	—				—		—			(7		)
Renewable energy adjustment	—			4			—				—		—			4
Zero-emission credits	—			21			—				—		—			21
Recovery of FAC under-recovery	3			—			—				—		—			3
Other cost recovery mechanisms:^(e)
Bad debt, energy efficiency programs, and remediation cost riders	—			(20		)	—				—		—			(20		)
MEEIA program costs	6			—			—				—		—			6
Total electric revenue change	$	(46	)	$	(98	)	$	—			$	11	$	2		$	(131	)
Fuel and purchased power change:
Energy costs (excluding the effect of weather and the New Madrid Smelter)	$	37		$	—		$	—			$	—	$	—		$	37
New Madrid Smelter energy costs	(6		)	—			—				—		—			(6		)
Effect of weather (estimate)^(b)	7			2			—				—		—			9
Effect of lower net energy costs included in base rates	20			—			—				—		—			20
Transmission services charges	(5		)	—			—				—		—			(5		)
Other	(9		)	2			—				—		(5		)	(12		)
Cost recovery mechanisms – offset in electric revenue:^(d)
Power supply costs	—			7			—				—		—			7
Renewable energy adjustment	—			(4		)	—				—		—			(4		)
Zero-emission credits	—			(21		)	—				—		—			(21		)
Recovery of FAC under-recovery	(3		)	—			—				—		—			(3		)
Total fuel and purchased power change	$	41		$	(14	)	$	—			$	—	$	(5	)	$	22
Net change in electric margins	$	(5	)	$	(112	)	$	—			$	11	$	(3	)	$	(109	)
Natural gas revenue change:
QIP rider	—			—			3				—		—			3
Other	—			—			(1		)		—		—			(1		)
Purchased natural gas costs – offset in natural gas purchased for resale^(d)	(2		)	—			(7		)		—		—			(9		)
Other cost recovery mechanisms:^(e)
Bad debt, energy efficiency programs, and remediation cost riders	—			—			2				—		—			2
Gross receipts tax	(1		)	—			1			—	—		—			—
Total natural gas revenue change	$	(3	)	$	—		$	(2	)		$	—	$	—		$	(5	)
Natural gas purchased for resale change:
Purchased natural gas costs – offset in natural gas revenue^(d)	2			—			7				—		—			9
Total natural gas purchased for resale change	$	2		$	—		$	7			$	—	$	—		$	9
Net change in natural gas margins	$	(1	)	$	—		$	5			$	—	$	—		$	4



Nine 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)	$	(72	)	$	(7	)	$	—		$	—	$	—		$	(79	)
Base rates (estimate)^(c)	53			31			—			43		—			127
FEJA impact on IEIMA – timing of revenue recognition	—			(47		)	—			—		—			(47		)
Recovery of power restoration efforts provided to other utilities	5			1			—			—		—			6
Sales volume (excluding the effect of weather and the New Madrid Smelter)	(4		)	—			—			—		—			(4		)
New Madrid Smelter revenues	(9		)	—			—			—		—			(9		)
MEEIA 2013 performance incentive	(19		)	—			—			—		—			(19		)
Off-system sales	94			—			—			—		—			94
Transmission services revenues	3			—			—			—		—			3
Other	8			(4		)	—			—		(1		)	3
Cost recovery mechanisms – offset in fuel and purchased power:^(d)
Power supply costs	—			(18		)	—			—		—			(18		)
Renewable energy adjustment	—			4			—			—		—			4
Zero-emission credits	—			21			—			—		—			21
Transmission services recovery mechanism	—			1			—			—		—			1
Recovery of FAC under-recovery	(7		)	—			—			—		—			(7		)
Other cost recovery mechanisms:^(e)
Bad debt, energy efficiency programs, and remediation cost riders	—			(17		)	—			—		—			(17		)
Gross receipts tax	1			—			—			—		—			1
MEEIA program costs	22			—			—			—		—			22
Total electric revenue change	$	75		$	(35	)	$	—		$	43	$	(1	)	$	82
Fuel and purchased power change:
Energy costs (excluding the effect of weather and the New Madrid Smelter)	$	(91	)	$	—		$	—		$	—	$	—		$	(91	)
New Madrid Smelter energy costs	1			—			—			—		—			1
Effect of weather (estimate)^(b)	16			—			—			—		—			16
Effect of lower net energy costs included in base rates	32			—			—			—		—			32
Transmission service charges	(7		)	—			—			—		—			(7		)
Other	(10		)	3			—			—		(3		)	(10		)
Cost recovery mechanisms – offset in electric revenue:^(d)
Power supply costs	—			18			—			—		—			18
Renewable energy adjustment	—			(4		)	—			—		—			(4		)
Zero-emission credits	—			(21		)	—			—		—			(21		)
Transmission services recovery mechanism	—			(1		)	—			—		—			(1		)
Recovery of FAC under-recovery	7			—			—			—		—			7
Total fuel and purchased power change	$	(52	)	$	(5	)	$	—		$	—	$	(3	)	$	(60	)
Net change in electric margins	$	23		$	(40	)	$	—		$	43	$	(4	)	$	22
Natural gas revenue change:
Effect of weather (estimate)^(b)	$	(6	)	$	—		$	—		$	—	$	—		$	(6	)
QIP rider	—			—			6			—		—			6
Other	(1		)	—			(2		)	—		—			(3		)
Purchased natural gas costs – offset in natural gas purchased for resale^(d)	1			—			(27		)	—		—			(26		)
Other cost recovery mechanisms:^(e)
Bad debt, energy efficiency programs, and remediation cost riders	—			—			3			—		—			3
Gross receipts tax	(1		)	—			—			—		—			(1		)
Total natural gas revenue change	$	(7	)	$	—		$	(20	)	$	—	$	—		$	(27	)
Natural gas purchased for resale change:
Effect of weather (estimate)^(b)	$	5		$	—		$	—		$	—	$	—		$	5
Purchased natural gas costs – offset in natural gas revenue^(d)	(1		)	—			27			—		—			26
Total natural gas purchased for resale change	$	4		$	—		$	27		$	—	$	—		$	31
Net change in natural gas margins	$	(3	)	$	—		$	7		$	—	$	—		$	4


(a)	Includes a decrease in transmission margins of $1 million and an increase of $10 million for the three- and nine-month 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 Other Operations and Maintenance Expenses or Taxes Other Than Income Taxes in this section for the related offsetting increase or decrease to expense. These items have no overall impact on earnings.

Ameren

Ameren's electric margins decreased $109 million, or 8%, for the three months ended September 30, 2017, compared with the year-ago period, primarily because of decreased margins at Ameren Illinois Electric Distribution. Ameren’s electric margins increased $22 million, or 1%, for the nine months ended September 30, 2017, compared with the year-ago period, primarily because of increased margins at Ameren Transmission and Ameren Missouri, partially offset by decreased margins at Ameren Illinois Electric Distribution.

Ameren's natural gas margins increased $4 million, or 4%, and $4 million, or 1%, for the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, primarily because of increased margins at Ameren Illinois Natural Gas, partially offset by decreased margins at Ameren Missouri.

Ameren Transmission

Ameren Transmission's margins increased $11 million, or 10%, and $43 million, or 15%, for the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods. Margins were favorably affected by increased capital investment, as evidenced by a 22% increase in rate base used to calculate the revenue requirement at September 30, 2017, compared to September 30, 2016, as well as higher recoverable costs for the three and nine months ended September 30, 2017, compared with the year-ago periods, under forward-looking formula ratemaking. Margins were unfavorably affected for the three and nine months ended September 30, 2017, compared with the year-ago periods, by the absence of a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 complaint case. See Note 2 – Rate and Regulatory Matters under Part 1, Item 1 of this report for information regarding the allowed return on common equity for FERC-regulated transmission rate base.

Ameren Missouri

Ameren Missouri's electric margins decreased $5 million, or 1%, for the three months ended September 30, 2017, compared with the year-ago period. Ameren Missouri’s electric margins increased $23 million, or 1%, for the nine months ended September 30, 2017, compared with the year-ago period. Ameren Missouri’s natural gas margins were comparable for the three months ended September 30, 2017, compared with the year-ago period. Ameren Missouri’s natural gas margins decreased $3 million, or 5%, for the nine months ended September 30, 2017, compared with the year-ago period.

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

•

Higher electric base rates, effective April 1, 2017, as a result of the March 2017 electric rate order, increased margins by an estimated $49 million and $85 million, respectively. The change in electric base rates is the sum of the change in base rates (estimate) (+$29 million and +$53 million, respectively) and the effect of lower net energy costs included in base rates (+$20 million and +$32 million, respectively) in the Electric and Natural Gas Margins table above.


•	Excluding the estimated effect of weather, residential sales volumes increased by less than 1% for the three months ended September 30, 2017, compared with the year-ago period, which increased margins by $8 million, as a result of customer growth.


•	The recovery of labor and benefit costs for crews assisting other utilities with power restoration efforts primarily caused by hurricane damage, which increased revenues by $5 million for both periods and was fully offset by a related increase in operations and maintenance costs, with no overall impact on net income.


•	Increased transmission services revenues due to additional rate base investment, which increased margins by $2 million and $3 million, respectively.

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

•

Summer temperatures were milder as cooling degree days decreased 11% and 8% for the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, and winter temperatures were milder as heating degree days decreased 15% for the nine months ended September 30, 2017, compared with the year-ago period. The effect of weather decreased margins by an estimated $26 million and $56 million, respectively. The change in margins due to weather is the sum of the effect of weather (estimate)

on electric revenues (-$33 million and -$72 million, respectively) and the effect of weather (estimate) on fuel and purchased power (+$7 million and +$16 million, respectively) in the Electric and Natural Gas Margins table above.


•	The absence in 2017 of the MEEIA 2013 performance incentive, which increased margins by $19 million for the three and nine months ended September 30, 2016.

•

Suspension of operations at the New Madrid Smelter in the first quarter of 2016 and the elimination of recovery under the FAC tariff effective April 1, 2017, which had allowed Ameren Missouri to retain a portion of the revenues from off-system sales it made as a result of reduced sales to the New Madrid Smelter, which decreased margins by $7 million and $8 million, respectively. As of April 1, 2017, higher electric base rates offset the absence of these revenues recovered under the FAC tariff. The decrease in margins due to the suspension of operations and elimination of the provision in the FAC tariff is the sum of New Madrid Smelter revenues (-$1 million and -$9 million, respectively) and New Madrid Smelter energy costs (-$6 million and +$1 million, respectively).


•	Increased transmission services charges resulting from additional MISO-approved electric transmission investments made by other entities and shared by all MISO participants, which decreased margins by $5 million and $7 million, respectively.

•

Excluding the estimated effect of weather and reduced sales to the New Madrid Smelter, total retail sales volumes decreased by less than 1% for the nine months ended September 30, 2017, compared with the year-ago period, which decreased margins by $4 million 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 $3 million for nine months ended September 30, 2017, compared with the year-ago period. The change in net energy costs is the sum of the change in off-system sales (+$94 million for the nine months ended September 30, 2017) and the change in energy costs (excluding the effect of weather and the New Madrid Smelter) (-$91 million for the nine months ended September 30, 2017) in the Electric and Natural Gas Margins table above.

Ameren Illinois

Ameren Illinois' electric margins decreased by $113 million, or 25%, and $30 million, or 3%, for the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, driven by a decrease in Ameren Illinois Electric Distribution ($112 million and $40 million, respectively). Ameren Illinois Natural Gas’ margins increased by $5 million, or 6%, and $7 million, or 2%, for the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, primarily due to increased rate base in 2017 under the QIP rider, which increased margins by $3 million and $6 million, respectively.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins decreased $112 million, or 30%, and $40 million or 5%, for the three and nine months ended September 30, 2017, 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 nine months ended September 30, 2017, compared with the year-ago periods:


•	A change in the method used to recognize interim period revenue, in connection with the decoupling provisions of the FEJA, which decreased margins by $94 million and $47 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.

•

The absence of the impact of warmer-than-normal summer temperatures experienced in the third quarter of 2016 and the decoupling of revenues in 2017, which decreased margins by $7 million for both periods. The change in margins due to weather is the sum of the effect of weather (estimate) on revenues (-$9 million and -$7 million, respectively) and the effect of weather (estimate) on fuel and purchased power (+$2 million and flat, respectively) in the Electric and Natural Gas Margins table above.

Ameren Illinois Electric Distribution’s base rates were favorably affected by increased recoverable expenses and rate base, as well as a higher 30-year United States Treasury bond yield under formula ratemaking, which collectively increased margins by $10 million and $31 million, respectively.

Ameren Illinois Transmission

Ameren Illinois Transmission's margins decreased $1 million, or 1%, for the three months ended September 30, 2017, compared to the year-ago period. Ameren Illinois Transmission’s margins increased $10 million, or 5%, for the nine months ended September 30, 2017, compared with the year-ago period. Margins were unfavorably affected for the three and nine months ended September 30, 2017, compared with the year-ago periods, by the absence of a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 complaint case. Margins were favorably affected by increased capital investment, as evidenced by a 15% increase in rate base used to calculate the revenue requirement at September 30, 2017, compared to September 30, 2016, as well as higher recoverable costs for the three and nine months ended September 30, 2017, compared with the year-ago periods, under forward-looking formula ratemaking.

Other Operations and Maintenance Expenses

Ameren

Other operations and maintenance expenses were $9 million and $17 million lower in the three and nine months ended September 30, 2017, respectively, as compared with the year-ago periods, as discussed below.

Ameren Transmission

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

Ameren Missouri

Other operations and maintenance expenses were $4 million higher and $15 million lower in the three and nine months ended September 30, 2017, respectively, as compared with the year-ago periods. The following items decreased other operations and maintenance expenses for the three and nine months ended September 30, 2017, compared with the year-ago periods (except where a specific period is referenced):


•	Refueling and maintenance outage costs at the Callaway energy center were lower by $27 million in the nine-month period, as the current year refueling and maintenance outage began in October 2017, while the 2016 refueling and maintenance outage was completed in the second quarter.


•	Pension and benefit costs decreased by $5 million and $10 million, respectively, primarily as a result of the March 2017 MoPSC electric rate order.


•	Solar rebate amortization costs decreased by $3 million and $6 million, respectively, primarily as a result of the March 2017 MoPSC electric rate order.


•	Estimated litigation costs decreased by $3 million and $5 million, respectively.

The following items increased other operations and maintenance expenses for the three and nine months ended September 30, 2017, compared with the year-ago periods:


•	MEEIA customer energy efficiency program costs increased by $6 million and $22 million, respectively. Electric revenues related to MEEIA program costs increased by a corresponding amount, with no overall effect on net income.


•	Ameren Missouri incurred $5 million of labor and benefit costs in both periods for crews assisting other utilities with power restoration, primarily caused by hurricane damage. These costs are being recovered from the other utilities, with no overall effect on net income.


•	Energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center, increased by $5 million in both periods, primarily because of higher coal handling charges.

Ameren Illinois

Other operations and maintenance expenses were $15 million lower in the three months ended September 30, 2017, compared with the year-ago period, as discussed below. Other operations and maintenance expenses were comparable in the nine months ended September 30, 2017, with the year-ago period. Other operations and maintenance expenses were comparable in the three and nine months ended September 30, 2017, with the year-ago periods, at Ameren Illinois Transmission.

Ameren Illinois Electric Distribution

Other operations and maintenance expenses decreased $14 million and $8 million in the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, primarily because of decreased customer energy efficiency and environmental remediation costs, which are included in cost recovery mechanisms resulting in decreased electric revenues, with no overall effect on net income. These decreases were partially offset by an increase in storm-related repair costs, as well as increased wages and staffing additions.

Ameren Illinois Natural Gas

Other operations and maintenance expenses were comparable in the three months ended September 30, 2017, with the year-ago period. Other operations and maintenance expenses increased $6 million in the nine months ended September 30, 2017, compared with the year-ago period, primarily because of increased bad debt, customer energy efficiency, and environmental remediation costs, which are included in cost recovery mechanisms resulting in increased natural gas revenues, with no overall effect on net income. In addition, higher gas pipeline compliance costs contributed to the increase.

Depreciation and Amortization

Depreciation and amortization expenses increased $14 million and $40 million at Ameren, $4 million and $15 million at Ameren Missouri, and $6 million and $17 million at Ameren Illinois in the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, primarily because of additional property, plant, and equipment across their respective segments.

Taxes Other Than Income Taxes

Taxes other than income taxes were comparable at each of the Ameren Companies and their respective segments in the three months ended September 30, 2017, with the year-ago period. Taxes other than income taxes increased $6 million at Ameren in the nine months ended September 30, 2017, compared with the year-ago period, primarily because of higher property taxes at Ameren Missouri and at each Ameren Illinois segment.

Other Income and Expenses

Ameren

Other income, net of expenses, was comparable in the three months ended September 30, 2017, with the year-ago period. Other income, net of expenses, decreased $7 million in the nine months ended September 30, 2017, compared with the year-ago period, as discussed below. See Note 5 – Other Income and Expenses under Part I, Item 1, of this report for additional information.

Ameren Transmission

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

Ameren Missouri

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

Ameren Illinois

Other income, net of expenses, was comparable in the three months ended September 30, 2017, with the year-ago period, for Ameren Illinois and each of its segments. Other income, net of expenses, decreased $5 million in the nine months ended September 30, 2017, compared with the year-ago period, primarily because of lower interest income associated with the IEIMA revenue requirement reconciliation at Ameren Illinois Electric Distribution. Other income, net of expenses, was comparable in the nine months ended September 30, 2017, with the year-ago period, for the remaining Ameren Illinois segments.

Interest Charges

Ameren

Interest charges were comparable in the three months ended September 30, 2017, with the year-ago period. Interest charges increased $8 million in the nine months ended September 30, 2017, compared with the year-ago period, as discussed below.

Ameren Transmission

Interest charges were comparable in the three months ended September 30, 2017, with the year-ago period. Interest charges increased $6 million in the nine months ended September 30, 2017, compared with the year-ago period, primarily because of an increase in average outstanding debt at Ameren Illinois and ATXI.

Ameren Missouri

Interest charges were comparable in the three and nine months ended September 30, 2017, with the year-ago periods.

Ameren Illinois

Interest charges were comparable in the three months ended September 30, 2017, with the year-ago period, for Ameren Illinois and each of its segments. Interest charges increased $4 million in the nine months ended September 30, 2017, compared with the year-ago period, primarily because of an increase in average outstanding debt at Ameren Illinois.

Income Taxes

The following table presents effective income tax rates for the three and nine months ended September 30, 2017 and 2016:



	Three Months^(a)				Nine Months^(a)
	2017		2016		2017		2016
Ameren	41	%	39	%	39	%	36	%
Ameren Missouri	38	%	38	%	38	%	38	%
Ameren Illinois	40	%	39	%	40	%	39	%
Ameren Illinois Electric Distribution	38	%	40	%	39	%	39	%
Ameren Illinois Natural Gas	51	%	20	%	40	%	39	%
Ameren Illinois Transmission	42	%	38	%	40	%	38	%
Ameren Transmission	44	%	38	%	41	%	39	%


(a)	Estimate of the annual effective income tax rate adjusted to reflect the tax effect of items discrete to the three and nine months ended September 30, 2017 and 2016.

Ameren

The effective income tax rate was higher in the three and nine months ended September 30, 2017, compared with the year-ago periods, because of an increase in the Illinois statutory income tax rate, which became effective on July 1, 2017. Additionally, the effective income tax rate was higher in the nine-month period because of a decrease in the recognition of income tax benefits associated with share-based compensation.

Ameren Transmission

The effective income tax rate was higher in the three and nine months ended September 30, 2017, compared with the year-ago periods, primarily because of the decreased effect of income tax benefits from certain depreciation differences on property-related items, along with the increase in the Illinois statutory income tax rate.

Ameren Missouri

The effective income tax rate was comparable in the three and nine months ended September 30, 2017, with the year-ago periods.

Ameren Illinois

The effective income tax rate was comparable in the three and nine months ended September 30, 2017, with the year-ago periods at Ameren Illinois, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission, except as discussed below.

Ameren Illinois Electric Distribution

The effective income tax rate was lower in the three months ended September 30, 2017, compared with the year-ago period, primarily because of the increased effect of income tax benefits on lower pretax income in the current year from certain depreciation differences on property-related items, partially offset by the increase in the Illinois statutory income tax rate.

Ameren Illinois Natural Gas

The effective income tax rate was higher in the three months ended September 30, 2017, compared with the year-ago period, primarily because of the decreased effect of income tax benefits on higher pretax income in the current year from certain depreciation differences on property-related items, as well as the increase in the Illinois statutory income tax rate. Due to the small amount of pretax income in the third quarter of each year, the effective income tax rates in both periods can vary significantly.

Ameren Illinois Transmission

The effective income tax rate was higher in the three months ended September 30, 2017, compared with the year-ago period, primarily because of a decrease in the income tax benefits from certain depreciation differences on property-related items, along with the increase in the Illinois statutory income tax rate.

LIQUIDITY AND CAPITAL RESOURCES

Collections from our tariff-based revenues are our principal source of cash provided by operating activities. A diversified retail customer mix, primarily consisting of rate-regulated residential, commercial, and industrial customers, provides us with a reasonably predictable source

of cash. In addition to using cash provided by operating activities, we use available cash, borrowings under the Credit Agreements, commercial paper issuances, 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). We expect to make significant capital expenditures over the next five years as we invest in our electric and natural gas utility infrastructure to support overall system reliability, environmental compliance, and other improvements. We intend to fund those capital expenditures primarily with cash provided by operating activities and short-term and long-term debt issuances so that we maintain an equity ratio around 50%, assuming constructive regulatory environments.

The use of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at September 30, 2017, for the Ameren Companies. The working capital deficit as of September 30, 2017, was primarily the result of current maturities of long-term debt and our decision to finance our businesses with lower-cost commercial paper issuances. With the credit capacity available under the Credit Agreements, the Ameren Companies had access to $1.7 billion of liquidity at September 30, 2017.

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



	Net Cash Provided By Operating Activities							Net Cash Used In Investing Activities									Net Cash Provided by (Used In) Financing Activities
	2017		2016		Variance			2017			2016			Variance			2017			2016			Variance
Ameren^(a)	$	1,643	$	1,559	$	84		$	(1,585	)	$	(1,551	)	$	(34	)	$	(58	)	$	(282	)	$	224
Ameren Missouri	819		888		(69		)	(455		)	(724		)	269			(364		)	(362		)	(2		)
Ameren Illinois	628		627		1			(754		)	(679		)	(75		)	126			(16		)	142


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

Cash Flows from Operating Activities

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

Ameren

Ameren’s cash from operating activities increased $84 million in the first nine months of 2017, compared with the year-ago period. The following items contributed to the increase:


•	A $160 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 $26 million decrease in payments for scheduled nuclear refueling and maintenance outages at Ameren Missouri’s Callaway energy center, as the current year refueling and maintenance outage began in October 2017, while the 2016 refueling and maintenance outage was completed in the second quarter.


•	A $23 million increase in cash collected from Ameren Illinois’ alternative retail electric supplier customers for renewable energy credit compliance pursuant to the FEJA.


•	A $21 million increase in cash collected from Ameren Illinois customers related to zero-emission credits pursuant to the FEJA.


•	A $12 million increase in net energy costs collected from Ameren Missouri customers under the FAC.


•	An increase of $12 million in income tax refunds primarily as a result of higher tax credit sales and the receipt of a 2010 Illinois income tax refund.

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


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


•	A $35 million increase in expenditures for customer energy efficiency programs at Ameren Illinois compared with amounts collected from customers.


•	A $30 million decrease in cash recoveries associated with 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.


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


•	An $18 million increase in purchased power costs collected from Ameren Illinois customers under the PGA.


•	A $13 million increase in payments related to natural gas held in storage caused primarily by reduced withdrawals as a result of milder winter temperatures compared with the prior year.

Ameren Missouri

Ameren Missouri’s cash from operating activities decreased $69 million in the first nine months of 2017, compared with the year-ago period. The following items contributed to the decrease:


•	An increase in income tax payments of $115 million to Ameren (parent) pursuant to the tax allocation agreement, primarily related to higher taxable income in 2017, due to significantly lower property-related deductions.


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

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


•	A $62 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 $26 million decrease in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center, as the current year refueling and maintenance outage began in October 2017, while the 2016 refueling and maintenance outage was completed in the second quarter.


•	A $12 million increase in net energy costs collected from customers under the FAC.

Ameren Illinois

Ameren Illinois’ cash from operating activities increased $1 million in the first nine months of 2017, compared with the year-ago period. The following items contributed to the increase:


•	An $84 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 $23 million increase in cash collected from alternative retail electric supplier customers for renewable energy credit compliance pursuant to the FEJA.


•	A $21 million increase in cash collected from customers related to zero-emission credits pursuant to the FEJA.


•	An increase of $15 million in income tax refunds from Ameren (parent) pursuant to the tax allocation agreement, primarily related to a larger taxable loss in 2017, due to higher property-related deductions and use of net operating losses.

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


•	A $35 million increase in expenditures for customer energy efficiency programs compared with amounts collected from customers.


•	A $30 million decrease in cash recoveries associated with IEIMA revenue requirement reconciliation adjustments. The 2015 revenue requirement reconciliation adjustment, which is being recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.


•	An $18 million increase in purchased power costs collected from customers under the PGA.


•	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 $13 million increase in interest payments, primarily due to an increase in the average outstanding debt.


•	A $12 million increase in payments related to natural gas held in storage caused primarily by reduced withdrawals as a result of milder winter temperatures compared with the prior year.


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

Cash Flows from Investing Activities

Ameren’s cash used in investing activities increased $34 million in the first nine months of 2017, compared with the year-ago period. Capital expenditures increased $27 million as a result of activity at Ameren Missouri and Ameren Illinois, discussed below, partially offset by a $72 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 Spoon River project. Nuclear fuel expenditures increased $11 million as a result of the activity at Ameren Missouri, as discussed below.

Ameren Missouri’s cash used in investing activities decreased $269 million between periods, primarily due to net money pool advances. In 2017, Ameren Missouri received $143 million in returns of net money pool advances, compared to investing $165 million in money pool advances in 2016. The decrease was partially offset by increased capital expenditures of $33 million primarily related to electric distribution system reliability and energy center projects and investments in transmission communication technology, as well as an $11 million increase in nuclear fuel expenditures because of the timing of purchases in the first nine months of 2017, compared with the prior-year period.

Ameren Illinois’ cash used in investing activities increased $75 million between periods largely due to an increase in capital expenditures of $77 million primarily related to electric distribution and transmission system reliability projects, updates to natural gas main infrastructure, substation upgrades and investments in smart grid technology.

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 used in financing activities decreased $224 million during the first nine months of 2017, compared to the year-ago period. During the first nine months of 2017, Ameren utilized net proceeds of $737 million from the issuance of long-term indebtedness and net commercial paper issuances to repay at maturity $425 million of higher cost long-term indebtedness and to fund, in part, investing activities. In comparison, during the first nine months of 2016, Ameren used net proceeds of $456 million from the issuance of long-term indebtedness and net commercial paper issuances to repay at maturity $389 million of higher cost long-term indebtedness and to fund, in part, investing activities.

Ameren Missouri’s cash used in financing activities was comparable between periods. During the first nine months of 2017, Ameren Missouri issued $399 million of long-term indebtedness and used the proceeds, along with cash on hand, to repay at maturity $425 million of higher cost long-term indebtedness. In comparison, during the first nine months of 2016, Ameren Missouri issued $149 million of long-term indebtedness and used the proceeds, along with cash on hand, to repay at maturity $260 million of higher cost long-term indebtedness. In addition, during the first nine months of 2017, Ameren Missouri paid $332 million in common stock dividends compared with $285 million in dividend payments and the receipt of a $38 million capital contribution in the year-ago period.

Ameren Illinois’ financing activities provided cash of $126 million during the first nine months of 2017, compared with $16 million of cash used in financing activities during the year-ago period. During the first nine months of 2017, Ameren Illinois used proceeds from net commercial paper issuances of $118 million to fund, in part, investing activities. In comparison, during the first nine months of 2016, Ameren Illinois used proceeds from net commercial paper issuances to repay at maturity $129 million of higher cost long-term indebtedness. Ameren Illinois did not pay common stock dividends during the nine months ended September 30, 2017, compared to dividend payments of $95 million during the same period in 2016. Additionally, money pool borrowings decreased $43 million, compared with the year-ago period.

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

Credit Facility Borrowings and Liquidity

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

The following table presents Ameren’s consolidated liquidity as of September 30, 2017:



Ameren and Ameren Missouri:
Missouri Credit Agreement – borrowing capacity	$	1,000
Less: Ameren (parent) commercial paper outstanding	162
Missouri Credit Agreement – credit available	838
Ameren and Ameren Illinois:
Illinois Credit Agreement – borrowing capacity	1,100
Less: Ameren (parent) commercial paper outstanding	115
Less: Ameren Illinois commercial paper outstanding	169
Less: Letters of credit	1
Illinois Credit Agreement – credit available	815
Total Credit Available	$	1,653
Cash and cash equivalents	9
Total Liquidity	$	1,662

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

In addition, Ameren Missouri and Ameren Illinois may borrow cash from the utility money pool when funds are available. The rate of interest depends on the composition of internal and external funds in the utility money pool. Ameren Missouri and Ameren Illinois will access funds from the utility money pool, the Credit Agreements, or the commercial paper programs depending on which option offers the lowest interest rates.

The 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, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities through July 2019.

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

Long-term Debt and Equity

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



	Month Issued, Redeemed, or Matured	2017		2016
Issuances of Long-term Debt
Ameren Missouri:
2.95% Senior secured notes due 2027	June	$	399	$	—
3.65% Senior secured notes due 2045	June	—		149
ATXI:
3.43% Senior notes due 2050	June	$	150	$	—
3.43% Senior notes due 2050	August	$	300	$	—
Total Ameren long-term debt issuances		$	849	$	149
Redemptions and Maturities of Long-term Debt
Ameren Missouri:
6.40% Senior secured notes due 2017	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
Total Ameren long-term debt redemptions and maturities		$	425	$	389

In June 2017, Ameren Missouri issued $400 million of 2.95% senior secured notes due June 2027, with interest payable semiannually on June 15 and December 15 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.

Indebtedness Provisions and Other Covenants

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

At September 30, 2017, 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 a significant source of funding for capital requirements not satisfied by cash generated from our operating activities. Inability to raise capital on reasonable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing its current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri, and Ameren Illinois each believes that it will continue to have access to the capital markets. However, events beyond Ameren’s, Ameren Missouri’s, and Ameren Illinois’ control may create uncertainty in the capital markets or make access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.

Dividends

The amount and timing of Ameren’s common stock dividends are within the sole discretion of Ameren’s board of directors. Ameren’s board of directors has not set specific targets or payout parameters when declaring common stock dividends, but 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. On October 13, 2017, Ameren’s board of directors declared a quarterly common stock dividend of 45.75 cents per share payable on December 29, 2017, to shareholders of record on December 13, 2017, resulting in an annualized equivalent dividend rate of $1.83 per share. The previous annualized equivalent dividend rate, based on the common stock dividend declared and paid in the third quarter of 2017, was $1.76 per share.

See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of the Form 10-K for additional discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At September 30, 2017, none of these circumstances existed at Ameren, Ameren Missouri, or Ameren Illinois and, as a result, these companies were not restricted from paying dividends.

The following table presents common stock dividends declared and paid by Ameren Corporation to its common shareholders and by Ameren Missouri and Ameren Illinois to their parent, Ameren Corporation, for the nine months ended September 30, 2017 and 2016:



	Nine Months
	2017		2016
Ameren Missouri	$	332	$	285
Ameren Illinois	—		95
Ameren	320		309

Contractual Obligations

For a listing of our obligations and commitments, see Other Obligations in Note 9 – Commitments and Contingencies under Part I, Item 1, of this report. See Note 11 – Retirement Benefits under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan.

At September 30, 2017, total obligations related to minimum purchase commitments for coal, natural gas, nuclear fuel, purchased power, methane gas, equipment, and meter reading services, among other agreements, at Ameren, Ameren Missouri, and Ameren Illinois were $2,649 million, $1,806 million, and $820 million, respectively.

Off-Balance-Sheet Arrangements

At September 30, 2017, none of the Ameren Companies had off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business, letters of credit, and Ameren parent guarantee arrangements on behalf of its subsidiaries.

Credit Ratings

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

The following table presents the principal credit ratings of the Ameren Companies 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 September 30, 2017. A sub-investment-grade issuer or senior unsecured debt rating (whether below “BBB-” from S&P or below “Baa3” from Moody’s) at September 30, 2017, could have resulted in Ameren, Ameren Missouri, or Ameren Illinois being required to post additional collateral or other assurances for certain trade obligations amounting to $89 million, $48 million, and $41 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at September 30, 2017, if market prices were 15% higher or lower than September 30, 2017 levels in the next 12 months and 20% higher or lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois could be required to post an immaterial amount, compared to each company’s liquidity, of collateral or other assurances for certain trade obligations.

OUTLOOK

We seek to earn competitive returns on investments in our businesses. We seek to improve our regulatory frameworks and cost recovery mechanisms and simultaneously pursuing constructive regulatory outcomes within existing frameworks, while also advocating for responsible energy policies. We seek to align our overall spending, both operating and capital, with economic conditions and with regulatory frameworks established by our regulators and to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We focus on minimizing the gap between allowed and earned returns on equity and allocating capital resources to our business opportunities that we expect to offer the most attractive risk-adjusted return potential.

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

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

Operations

•

Ameren continues to invest in FERC-regulated electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The Illinois Rivers project involves the construction of a transmission line from 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 2019. The Spoon River project, located in northwest Illinois, and the Mark Twain project, located in northeast Missouri and connecting the Illinois Rivers project to Iowa, are the other two MISO-approved projects to be constructed by ATXI. Construction activities for the Spoon River project are continuing on schedule, and the project is expected to be completed in 2018. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding the Mark Twain project and its approval process and the Illinois Rivers project. The total investment in all three projects is expected to be more than $540 million from 2017 through 2019. Ameren Illinois expects to invest $2.2 billion in electric transmission assets from 2017 through 2021 to replace aging infrastructure and improve reliability.

•

Both Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Based on the preliminary rate calculations that will become effective on January 1, 2018, and the currently allowed 10.82% return on common equity, the 2018 revenue requirement that is expected to be collected in rates for Ameren Illinois’ electric transmission business is $297 million. The 2018 rates reflect a $38 million increase over the 2017 revenue requirement, primarily due to rate base growth. These rates reflect a capital structure comprised of 51.6% common equity and a projected average rate base of $1.6 billion. Based on the preliminary rate calculations that will become effective on January 1, 2018, and the currently allowed 10.82% return on equity, the 2018 revenue requirement that is expected to be collected in rates for ATXI’s electric transmission business is $197 million. The 2018 rates represents a $27 million increase over the 2017 revenue requirement, primarily due to rate base growth. These rates reflect a capital structure comprised of 56.2% common equity and a projected average rate base of $1.3 billion, reflecting additional investments in the Illinois Rivers and Spoon River projects.

•

The return on common equity for MISO transmission owners, including Ameren Illinois and ATXI, was the subject of two FERC complaint proceedings, the November 2013 complaint case and the February 2015 complaint case, that each challenged the allowed base return on common equity. 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. 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 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 require customer refunds, with interest, for that 15-month period. The timing of the issuance of the final order in the February 2015 complaint case is uncertain for two reasons. First, while the FERC reestablished a quorum of commissioners in August 2017 after six months without a quorum, the FERC is 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. In addition, 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. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding the MISO transmission owners’ motion to dismiss the February 2015 complaint case. A 50 basis point reduction in the FERC-allowed base return on common equity would reduce Ameren's and Ameren Illinois' annual earnings by an estimated $7 million and $4 million, respectively, based on each company’s 2017 projected rate base. Ameren and Ameren Illinois recorded current regulatory liabilities on their respective September 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 revenue requirement necessary to reflect the actual costs incurred and investment return in a given year with the revenue requirement that was reflected in customer rates for that year. Consequently, Ameren Illinois' 2017 electric distribution service revenues will be based on its 2017 actual recoverable costs, rate base, and return on common equity as calculated under the Illinois performance-based formula ratemaking framework. The 2017 revenue

requirement is expected to be higher than the 2016 revenue requirement because of an expected increase in recoverable costs, expected rate base growth of 5%, and an expected increase in the monthly average of 30-year United States Treasury bonds. The 2017 revenue requirement reconciliation is expected to result in a regulatory asset that will be collected from customers in 2019. A 50 basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $7 million change in Ameren's and Ameren Illinois' net income, based on Ameren Illinois’ 2017 projected year-end rate base.

•

In April 2017, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for 2018 rates. In June 2017, 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. Pending ICC approval, this update filing will result in a $17 million decrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2018. These rates will affect Ameren Illinois' cash receipts during 2018, but will not determine its electric distribution service operating revenues, which will instead be based on its 2018 actual recoverable costs, rate base, and return on common equity as calculated under the Illinois performance-based formula ratemaking framework. In November 2017, an administrative law judge issued a proposed order that was consistent with Ameren Illinois’ revised July 2017 filing. An ICC decision on the revenue requirement used for 2018 rates is expected by December 2017.

•

Beginning in 2017, the FEJA provides that Ameren Illinois recovers, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes. In connection with the decoupling provisions of the FEJA, Ameren Illinois changed its method used to recognize its interim period revenue. Ameren Illinois 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 incurred quarterly year-over-year increases to earnings in 2017 in comparison to 2016 for the first and second quarters and a decrease to earnings in the third quarter. Ameren Illinois expects an estimated $28 million increase to earnings in the fourth quarter of 2017 in comparison to 2016 as a result of the change. The change in interim period revenue recognition will not impact 2017’s annual earnings.

•

Beginning in June 2017, the FEJA allows Ameren Illinois to earn a return on its electric energy efficiency program investments. Ameren Illinois electric energy efficiency investments will be deferred as a regulatory asset and will earn a return at the company’s weighted average cost of capital, with the equity return based on the monthly average yield of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ return on electric energy efficiency investments can also be increased or decreased by 200 basis points based on the achievement of annual energy savings goals. Based on Ameren Illinois’ 2018 through 2021 energy efficiency plan and a formula provided in the FEJA, Ameren Illinois estimates it can annually invest up to $99 million from 2018 through 2021, up to $107 million annually from 2022 through 2025, and up to $114 million annually from 2026 through 2030. The ICC has the ability to lower the electric energy efficiency saving goals if there are insufficient cost effective measures available or if achieving the savings goals would require investment levels that exceed the formula amounts shown above. The electric energy efficiency program investments and the return on those investments will be recovered through a rider and will not be included in the IEIMA formula rate process. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding Ameren Illinois approved energy efficiency program for 2018 through 2021.

•

In July 2017, Illinois enacted a law that increased the state's corporate income tax rate from 7.75% to 9.5% as of July 1, 2017. The law made the increase in the state’s corporate income tax rate, which was previously scheduled to decrease to 7.3% in 2025, permanent. In July 2017, Ameren recorded 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 expense, 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 the Ameren Illinois Electric Distribution, the Ameren Transmission, or the 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 customer rates are reset in a rate review to reflect the increased taxes.


•	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 2016 future test year.

•

Ameren Missouri's scheduled refueling and maintenance outage at its Callaway energy center began in October 2017. Ameren Missouri expects to incur $32 million of maintenance expenses, which approximates the cost of the spring 2016 outage. During a scheduled outage, which occurs every 18 months, maintenance expenses increase relative to non-outage years. Additionally, depending on the availability of its other generation sources and the market prices for power, Ameren Missouri's purchased power costs may increase and the amount of excess power available for sale may decrease versus non-outage years. Changes in purchased power costs and excess

power available for sale are included in the FAC, which results in limited impacts to earnings. Ameren Missouri does not have a scheduled refueling and maintenance outage in 2018.

•

Ameren and Ameren Missouri expect an approximately $15 million decrease in annual interest charges as a result of the repayment of $425 million of Ameren Missouri’s 6.40% senior secured notes at maturity and issuance of $400 million 2.95% senior secured notes in 2017. In 2018, Ameren Missouri expects to refinance maturing long-term debt with lower-cost long-term debt, which would further reduce Ameren’s and Ameren Missouri’s annual interest charges.

•

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 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, 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. Increased costs are also expected from rising employee benefit costs, higher property taxes, and higher state income taxes, among other costs.

For additional information regarding recent rate orders, lawsuits, the Westinghouse bankruptcy filing, and pending requests filed with state and federal regulatory commissions, see Note 2 – Rate and Regulatory Matters and Note 10 – Callaway Energy Center under Part I, Item 1, of this report and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K.

Liquidity and Capital Resources

•

Ameren Missouri files a non-binding 20-year integrated resource plan with the MoPSC every three years. Ameren Missouri’s integrated resource plan filed with the MoPSC in September 2017 includes Ameren Missouri’s preferred plan for meeting customers’ projected long-term energy needs in a cost-effective fashion that maintains system reliability as it targets cleaner and more diverse sources of energy generation. These new renewable energy sources would also 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. Ameren Missouri’s plan contemplates adding at least 700 megawatts of wind generation by 2020, as well as 100 megawatts of solar generation over the next 10 years, with 50 megawatts anticipated to come online by 2025. The new wind generation is expected to be located in Missouri and neighboring states. The source, location, and cost of the new wind generation, among other items, remain subject to reaching agreements with developers. 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 alternative for customers. The plan also includes expected implementation of continued customer energy efficiency programs. Ameren Missouri’s plan for the addition of renewable resources could be impacted by, among other factors: the availability of federal production tax credits related to renewable energy and its ability to use such credits; the cost of wind and solar generation technologies, as well as energy prices; Ameren Missouri’s ability to obtain 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, or any other required project approvals.


•	In connection with the integrated resource plan filing, discussed above, 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 its useful life.

•

Through 2021, we expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure, with a major portion directed to our transmission and distribution systems. We estimate that we will invest in total up to $11.2 billion (Ameren Missouri – up to $4.2 billion; Ameren Illinois – up to $6.4 billion; ATXI – up to $0.6 billion) of capital expenditures during the period from 2017 through 2021. These estimates do not reflect the potential additional investments identified in Ameren Missouri’s integrated resource plan discussed above, which could represent incremental investments of approximately $1 billion and are subject to regulatory approval. Ameren and Ameren Missouri will evaluate alternatives for funding these potential additional investments.

•

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 by the EPA, so their ultimate implementation, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing environmental regulations could result in significant capital expenditures, increased operating costs, the closure or alteration of some of Ameren Missouri's coal-fired energy centers, or require further capital investment. Ameren Missouri's capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances as well as regulatory

lag. The cost of Ameren Illinois’ purchased power and natural gas purchased for resale could increase. However, Ameren Illinois expects these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. Ameren's and Ameren Missouri's earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in customer rates.

•

The Ameren Companies have multiyear credit agreements that cumulatively provide $2.1 billion of credit through December 2021, subject to a 364-day repayment term in the case of Ameren Missouri and Ameren Illinois. See Note 4 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information regarding the Credit Agreements. By the end of 2018, $378 million and $707 million of senior secured notes are scheduled to mature at Ameren Missouri and Ameren Illinois, respectively. Ameren Missouri and Ameren Illinois expect to refinance these senior secured notes, as well as a portion of any outstanding short-term debt at the time, with long-term debt. Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.

•

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

•

As of September 30, 2017, Ameren had $450 million in tax benefits from federal and state net operating loss carryforwards (Ameren Missouri – $4 million and Ameren Illinois – $115 million) and $116 million in federal and state income tax credit carryforwards (Ameren Missouri – $31 million and Ameren Illinois – $2 million). In addition, Ameren has $7 million of expected state income tax refunds and state overpayments. Consistent with the tax allocation agreement between Ameren and its subsidiaries, these carryforwards are expected to partially offset income tax liabilities for Ameren Missouri and Ameren Illinois until 2021. These tax benefits, primarily at the Ameren (parent) level, when realized, would be available to support funding Ameren Transmission investments. Based on existing tax laws, Ameren does not expect to make material federal income tax payments until 2021 and Ameren and Ameren Missouri do not expect to make material state income tax payments until 2021. Due to differences between federal and state tax laws, Ameren and Ameren Illinois expect to begin making material state income tax payments in 2018.

•

Since the 2016 presidential and congressional elections, there have been various legislative proposals to reform the federal income tax code. Tax law changes that would affect our businesses include those changes associated with the statutory federal corporate income tax rate, interest deductibility, tax deductions for capital investments, the availability of federal production tax credits and our ability to use them, and state and local tax deductibility. Changes to the normalization of income taxes for ratemaking and return of excess deferred tax liabilities to customers could also affect our businesses. Depending on the magnitude and mix of any implemented changes, federal income tax reform could materially affect 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. Ameren expects to use debt to fund such cash shortfalls. If cash flows change materially from those expected, such as the cash flow needs associated with the potential investments identified in Ameren Missouri’s integrated resource plan, Ameren will reevaluate its funding plan.

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

REGULATORY MATTERS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices, and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset or index. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the

forward-looking statements. We handle market risk in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal, and operational risks, are not part of the following discussion.

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

With the exception of the following, there have been no material changes to the quantitative and qualitative disclosures about interest rate risk, credit risk, equity price risk, commodity price risk, and commodity supplier risk included in the Form 10-K. In the first quarter of 2017, Ameren Missouri’s supplier of nuclear fuel assemblies, Westinghouse, filed a voluntary petition for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. At this time, Ameren and Ameren Missouri believe the restructuring proceeding will not affect Westinghouse’s performance under the terms of its existing contracts with Ameren Missouri, and therefore do not expect any material impact to Ameren Missouri’s operations as a result of this restructuring proceeding. Ameren Missouri 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, 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 nine months ended September 30, 2017. 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									Nine Months
	Ameren Missouri			Ameren Illinois			Ameren			Ameren Missouri			Ameren Illinois			Ameren
Fair value of contracts at beginning of period, net	$	2		$	(205	)	$	(203	)	$	(4	)	$	(180	)	$	(184	)
Contracts realized or otherwise settled during the period	(1		)	6			5			(3		)	2			(1		)
Fair value of new contracts entered into during the period	1			—			1			10			(2		)	8
Other changes in fair value	2			(5		)	(3		)	1			(24		)	(23		)
Fair value of contracts outstanding at end of period, net	$	4		$	(204	)	$	(200	)	$	4		$	(204	)	$	(200	)

The following table presents maturities of derivative contracts as of September 30, 2017, based on the hierarchy levels used to determine the fair value of the contracts:



Sources of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 3-5 Years			Maturity in Excess of 5 Years			Total Fair Value
Ameren Missouri:
Level 1	$	1		$	—		$	—		$	—		$	1
Level 2^(a)	(3		)	(4		)	—			—			(7		)
Level 3^(b)	8			2			—			—			10
Total	$	6		$	(2	)	$	—		$	—		$	4
Ameren Illinois:
Level 1	$	—		$	1		$	—		$	—		$	1
Level 2^(a)	(7		)	(4		)	—			—			(11		)
Level 3^(b)	(13		)	(29		)	(29		)	(123		)	(194		)
Total	$	(20	)	$	(32	)	$	(29	)	$	(123	)	$	(204	)
Ameren:
Level 1	$	1		$	1		$	—		$	—		$	2
Level 2^(a)	(10		)	(8		)	—			—			(18		)
Level 3^(b)	(5		)	(27		)	(29		)	(123		)	(184		)
Total	$	(14	)	$	(34	)	$	(29	)	$	(123	)	$	(200	)


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


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

ITEM 4. CONTROLS AND PROCEDURES.


(a)	Evaluation of Disclosure Controls and Procedures

As of September 30, 2017, 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 September 30, 2017, the principal executive officer and the principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive 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:


•	ATXI’s request for certificate of convenience and necessity from the MoPSC for the Mark Twain project;


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


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


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


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


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

ITEM 1A. RISK FACTORS.

A detailed discussion of our risk factors is included 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.

There has been an increase in the number and sophistication of cyber-attacks across all industries around the world. 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, employee, financial, and operating system information. 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.

Ameren, Ameren Missouri and Ameren Illinois did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from July 1, 2017 to September 30, 2017.

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 Illinois	Supplemental Indenture, dated as of October 25, 2017, to Ameren Illinois Mortgage
Statement re: Computation of Ratios
12.1	Ameren	Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.2	Ameren Missouri	Ameren Missouri’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.3	Ameren Illinois	Ameren Illinois’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
Rule 13a-14(a) / 15d-14(a) Certifications
31.1	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren
31.2	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren
31.3	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Missouri
31.4	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Missouri
31.5	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois
31.6	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois
Section 1350 Certifications
32.1	Ameren	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren
32.2	Ameren Missouri	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri
32.3	Ameren Illinois	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Illinois
Interactive Data Files
101.INS	Ameren Companies	XBRL Instance Document
101.SCH	Ameren Companies	XBRL Taxonomy Extension Schema Document
101.CAL	Ameren Companies	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	Ameren Companies	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Ameren Companies	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	Ameren Companies	XBRL Taxonomy Extension Definition Document

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

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

SIGNATURES

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

AMEREN CORPORATION

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

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

UNION ELECTRIC COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

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

AMEREN ILLINOIS COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

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

Date: November 3, 2017