Ameren Illinois Co - Quarter Report: 2015 September (Form 10-Q)

Ameren
Missouri

Ameren
Illinois

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, 2015



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



Commission File Number	Exact name of registrant as specified in its charter; State of Incorporation; Address and Telephone Number	IRS Employer Identification No.
1-14756	Ameren Corporation	43-1723446
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222

1-2967	Union Electric Company	43-0559760
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222

1-3672	Ameren Illinois Company	37-0211380
	(Illinois Corporation)
	6 Executive Drive
	Collinsville, Illinois 62234
	(618) 343-8150

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



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

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



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

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



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

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



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

The number of shares outstanding of each registrant’s classes of common stock as of October 30, 2015, was as follows:



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

______________________________________________________________________________________________________

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

TABLE OF CONTENTS



		Page
Glossary of Terms and Abbreviations		1

Forward-looking Statements		1

PART I Financial Information

Item 1.	Financial Statements (Unaudited)	3
	Ameren Corporation	3
	Consolidated Statement of Income	3
	Consolidated Statement of Comprehensive Income	4
	Consolidated Balance Sheet	5
	Consolidated Statement of Cash Flows	6
	Union Electric Company (d/b/a Ameren Missouri)	7
	Statement of Income and Comprehensive Income	7
	Balance Sheet	8
	Statement of Cash Flows	9
	Ameren Illinois Company (d/b/a Ameren Illinois)	10
	Statement of Income and Comprehensive Income	10
	Balance Sheet	11
	Statement of Cash Flows	12
	Combined Notes to Financial Statements	13
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	65
Item 4.	Controls and Procedures	66

PART II Other Information

Item 1.	Legal Proceedings	66
Item 1A.	Risk Factors	67
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	67
Item 6.	Exhibits	68

Signatures		69

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

GLOSSARY OF TERMS AND ABBREVIATIONS

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

Clean Power Plan - “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units,” an EPA rule that establishes emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired generating units.

FAC - Fuel adjustment clause, a fuel and purchased power cost recovery mechanism that allows Ameren Missouri 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.

Form 10-K - The combined Annual Report on Form 10-K for the year ended December 31, 2014, filed by the Ameren Companies with the SEC.

Net energy costs - Net energy costs, as defined in the FAC, include fuel and purchased power costs, including transportation, net of off-system sales. As of May 30, 2015, transmission revenues and substantially all transmission charges are excluded from net energy costs as a result of the April 2015 MoPSC electric rate order.

Net shared benefits - Ameren Missouri’s share of the present value of lifetime energy savings, net of program costs, designed to offset sales volume reductions resulting from Ameren Missouri’s customer energy efficiency programs.

FORWARD-LOOKING STATEMENTS

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

•

regulatory, judicial, or legislative actions, including changes in regulatory policies and ratemaking determinations, that may result from Ameren Illinois’ April 2015 annual electric delivery service formula update filing under the IEIMA; Ameren Illinois' January 2015 natural gas delivery service rate case filing; the complaint cases filed with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff; the complaint case filed with the MoPSC regarding the performance incentive for the 2013 through 2015 MEEIA plan; and future regulatory, judicial, or legislative actions that seek to change regulatory recovery mechanisms;

•

the effect of Ameren Illinois participating in a performance-based formula ratemaking process under the IEIMA, including the direct relationship between Ameren Illinois' return on common equity and 30-year United States Treasury bond yields, the related financial commitments required by the IEIMA, and the resulting uncertain impact on the financial condition, results of operations, and liquidity of Ameren Illinois;


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


•	the effects of increased competition in the future due to, among other factors, deregulation of certain aspects of our business at either the state or federal level;


•	changes in laws and other governmental actions, including monetary, fiscal, tax, and energy policies;


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


•	the effectiveness of Ameren Missouri's customer energy efficiency programs and the related amount of any net shared benefits and performance incentive earned under the current MEEIA plan and any future MEEIA plan;


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


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


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


•	the ability to obtain sufficient insurance, including insurance relating to Ameren Missouri’s Callaway energy center, and to recover the costs of such insurance or, in the absence of insurance, the ability to recover uninsured losses;


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


•	the financial condition of Noranda and any significant reductions in the sales volumes used by its aluminum smelter in southeast Missouri below the sales volumes assumed in determining Ameren Missouri’s electric rates;


•	revisions to Ameren Missouri’s long-term power supply agreement with Noranda, including Ameren Missouri’s notification to terminate the agreement effective June 1, 2020 and Ameren Missouri’s decision whether to seek MoPSC approval to cease providing electricity to Noranda thereafter;


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


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


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


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


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


•	the effects of our increasing investment in electric transmission projects and uncertainty as to whether we will achieve our expected returns in a timely fashion, if at all;


•	the extent to which Ameren Missouri prevails in its claim against an insurer in connection with the December 2005 breach of the upper reservoir at the Taum Sauk pumped-storage hydroelectric energy center;


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


•	the effects of strategic initiatives, including mergers, acquisitions and divestitures, and any related tax implications;

•

the impact of current environmental regulations and new, more stringent, or changing requirements, including those related to greenhouse gases, 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 our 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;


•	the inability of Dynegy and IPH to satisfy their indemnity and other obligations to Ameren in connection with the divestiture of New AER to IPH;


•	legal and administrative proceedings; and


•	acts of sabotage, war, terrorism, cyber attacks, 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,
	2015		2014			2015		2014
Operating Revenues:
Electric	$	1,700	$	1,523		$	4,093	$	3,864
Gas	133		147			697		819
Total operating revenues	1,833		1,670			4,790		4,683
Operating Expenses:
Fuel	259		236			670		638
Purchased power	153		114			393		340
Gas purchased for resale	38		49			320		432
Other operations and maintenance	428		402			1,256		1,231
Provision for Callaway construction and operating license (Note 2)	—		—			69		—
Depreciation and amortization	201		187			594		551
Taxes other than income taxes	128		121			369		362
Total operating expenses	1,207		1,109			3,671		3,554
Operating Income	626		561			1,119		1,129
Other Income and Expense:
Miscellaneous income	19		21			54		60
Miscellaneous expense	5		7			22		20
Total other income	14		14			32		40
Interest Charges	87		85			264		266
Income Before Income Taxes	553		490			887		903
Income Taxes	208		194			333		357
Income from Continuing Operations	345		296			554		546
Income (Loss) from Discontinued Operations, Net of Taxes (Note 12)	—		(1		)	52		(3		)
Net Income	345		295			606		543
Less: Net Income from Continuing Operations Attributable to Noncontrolling Interests	2		2			5		5
Net Income (Loss) Attributable to Ameren Common Stockholders:
Continuing Operations	343		294			549		541
Discontinued Operations	—		(1		)	52		(3		)
Net Income Attributable to Ameren Common Stockholders	$	343	$	293		$	601	$	538

Earnings (Loss) per Common Share – Basic:
Continuing Operations	$	1.42	$	1.21		$	2.27	$	2.23
Discontinued Operations	—		—			0.21		(0.01		)
Earnings per Common Share – Basic	$	1.42	$	1.21		$	2.48	$	2.22

Earnings (Loss) per Common Share – Diluted:
Continuing Operations	$	1.41	$	1.20		$	2.26	$	2.21
Discontinued Operations	—		—			0.21		(0.01		)
Earnings per Common Share – Diluted	$	1.41	$	1.20		$	2.47	$	2.20

Dividends per Common Share	$	0.41	$	0.40		$	1.23	$	1.20
Average Common Shares Outstanding – Basic	242.6		242.6			242.6		242.6
Average Common Shares Outstanding – Diluted	243.9		244.3			243.8		244.3

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,
	2015		2014			2015		2014
Income from Continuing Operations	$	345	$	296		$	554	$	546
Other Comprehensive Income from Continuing Operations, Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes of $-, $-, $4 and $3, respectively	—		—			4		3
Comprehensive Income from Continuing Operations	345		296			558		549
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests	2		2			5		5
Comprehensive Income from Continuing Operations Attributable to Ameren Common Stockholders	343		294			553		544

Income (Loss) from Discontinued Operations, Net of Taxes	—		(1		)	52		(3		)
Other Comprehensive Income from Discontinued Operations, Net of Taxes	—		—			—		—
Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Common Stockholders	—		(1		)	52		(3		)
Comprehensive Income Attributable to Ameren Common Stockholders	$	343	$	293		$	605	$	541

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, 2015			December 31, 2014
ASSETS
Current Assets:
Cash and cash equivalents	$	72		$	5
Accounts receivable – trade (less allowance for doubtful accounts of $20 and $21, respectively)	508			423
Unbilled revenue	234			265
Miscellaneous accounts and notes receivable	113			81
Materials and supplies	548			524
Current regulatory assets	163			295
Current accumulated deferred income taxes, net	225			352
Other current assets	103			86
Assets of discontinued operations (Note 12)	17			15
Total current assets	1,983			2,046
Property and Plant, Net	18,307			17,424
Investments and Other Assets:
Nuclear decommissioning trust fund	534			549
Goodwill	411			411
Regulatory assets	1,578			1,582
Other assets	646			664
Total investments and other assets	3,169			3,206
TOTAL ASSETS	$	23,459		$	22,676
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	395		$	120
Short-term debt	783			714
Accounts and wages payable	525			711
Taxes accrued	160			46
Interest accrued	103			85
Current regulatory liabilities	89			106
Other current liabilities	404			434
Liabilities of discontinued operations (Note 12)	30			33
Total current liabilities	2,489			2,249
Long-term Debt, Net	5,981			6,120
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	4,084			3,923
Accumulated deferred investment tax credits	62			64
Regulatory liabilities	1,894			1,850
Asset retirement obligations	597			396
Pension and other postretirement benefits	666			705
Other deferred credits and liabilities	530			514
Total deferred credits and other liabilities	7,833			7,452
Commitments and Contingencies (Notes 2, 9, 10 and 12)
Ameren Corporation Stockholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6	2			2
Other paid-in capital, principally premium on common stock	5,612			5,617
Retained earnings	1,405			1,103
Accumulated other comprehensive loss	(5		)	(9		)
Total Ameren Corporation stockholders’ equity	7,014			6,713
Noncontrolling Interests	142			142
Total equity	7,156			6,855
TOTAL LIABILITIES AND EQUITY	$	23,459		$	22,676

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,
	2015			2014
Cash Flows From Operating Activities:
Net income	$	606		$	543
(Income) loss from discontinued operations, net of taxes	(52		)	3
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for Callaway construction and operating license	69			—
Depreciation and amortization	582			526
Amortization of nuclear fuel	71			70
Amortization of debt issuance costs and premium/discounts	16			16
Deferred income taxes and investment tax credits, net	318			370
Allowance for equity funds used during construction	(19		)	(26		)
Stock-based compensation costs	20			20
Other	(8		)	(9		)
Changes in assets and liabilities:
Receivables	(71		)	16
Materials and supplies	(23		)	(34		)
Accounts and wages payable	(172		)	(187		)
Taxes accrued	114			100
Regulatory assets and liabilities	74			(216		)
Assets, other	20			44
Liabilities, other	(41		)	(21		)
Pension and other postretirement benefits	29			(27		)
Counterparty collateral, net	—			20
Net cash provided by operating activities – continuing operations	1,533			1,208
Net cash used in operating activities – discontinued operations	(5		)	(5		)
Net cash provided by operating activities	1,528			1,203
Cash Flows From Investing Activities:
Capital expenditures	(1,332		)	(1,310		)
Nuclear fuel expenditures	(30		)	(28		)
Purchases of securities – nuclear decommissioning trust fund	(301		)	(365		)
Sales and maturities of securities – nuclear decommissioning trust fund	290			354
Proceeds from note receivable – Marketing Company	12			79
Contributions to note receivable – Marketing Company	(8		)	(84		)
Other	7			3
Net cash used in investing activities – continuing operations	(1,362		)	(1,351		)
Net cash provided by investing activities – discontinued operations	—			139
Net cash used in investing activities	(1,362		)	(1,212		)
Cash Flows From Financing Activities:
Dividends on common stock	(298		)	(291		)
Dividends paid to noncontrolling interest holders	(5		)	(5		)
Short-term debt, net	69			385
Redemptions and maturities of long-term debt	(114		)	(692		)
Issuances of long-term debt	249			598
Capital issuance costs	(2		)	(4		)
Other	2			1
Net cash used in financing activities – continuing operations	(99		)	(8		)
Net cash used in financing activities – discontinued operations	—			—
Net cash used in financing activities	(99		)	(8		)
Net change in cash and cash equivalents	67			(17		)
Cash and cash equivalents at beginning of year	5			30
Cash and cash equivalents at end of period	$	72		$	13

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,
	2015		2014		2015		2014
Operating Revenues:
Electric	$	1,151	$	1,076	$	2,752	$	2,696
Gas	19		21		101		117
Other	1		—		2		1
Total operating revenues	1,171		1,097		2,855		2,814
Operating Expenses:
Fuel	259		236		670		638
Purchased power	29		27		87		91
Gas purchased for resale	5		7		43		58
Other operations and maintenance	233		226		673		672
Provision for Callaway construction and operating license (Note 2)	—		—		69		—
Depreciation and amortization	125		118		367		351
Taxes other than income taxes	97		89		262		248
Total operating expenses	748		703		2,171		2,058
Operating Income	423		394		684		756
Other Income and Expense:
Miscellaneous income	14		15		37		45
Miscellaneous expense	3		4		8		10
Total other income	11		11		29		35
Interest Charges	54		53		164		159
Income Before Income Taxes	380		352		549		632
Income Taxes	140		129		205		234
Net Income	240		223		344		398
Other Comprehensive Income	—		—		—		—
Comprehensive Income	$	240	$	223	$	344	$	398


Net Income	$	240	$	223	$	344	$	398
Preferred Stock Dividends	1		1		3		3
Net Income Available to Common Stockholder	$	239	$	222	$	341	$	395

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, 2015		December 31, 2014
ASSETS
Current Assets:
Cash and cash equivalents	$	69	$	1
Advances to money pool	250		—
Accounts receivable – trade (less allowance for doubtful accounts of $7 and $8, respectively)	260		190
Accounts receivable – affiliates	8		65
Unbilled revenue	148		146
Miscellaneous accounts and notes receivable	62		35
Materials and supplies	374		347
Current regulatory assets	97		163
Other current assets	57		92
Total current assets	1,325		1,039
Property and Plant, Net	11,041		10,867
Investments and Other Assets:
Nuclear decommissioning trust fund	534		549
Regulatory assets	646		695
Other assets	395		391
Total investments and other assets	1,575		1,635
TOTAL ASSETS	$	13,941	$	13,541
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	266	$	120
Short-term debt	—		97
Accounts and wages payable	187		405
Accounts payable – affiliates	35		56
Taxes accrued	273		32
Interest accrued	66		58
Current regulatory liabilities	41		18
Other current liabilities	116		117
Total current liabilities	984		903
Long-term Debt, Net	3,869		3,879
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	2,858		2,806
Accumulated deferred investment tax credits	59		61
Regulatory liabilities	1,166		1,147
Asset retirement obligations	590		389
Pension and other postretirement benefits	267		274
Other deferred credits and liabilities	30		30
Total deferred credits and other liabilities	4,970		4,707
Commitments and Contingencies (Notes 2, 8, 9 and 10)
Stockholders’ 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	1,784		1,569
Preferred stock	80		80
Retained earnings	1,743		1,892
Total stockholders’ equity	4,118		4,052
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	13,941	$	13,541

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,
	2015			2014
Cash Flows From Operating Activities:
Net income	$	344		$	398
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for Callaway construction and operating license	69			—
Depreciation and amortization	356			329
Amortization of nuclear fuel	71			70
Amortization of debt issuance costs and premium/discounts	5			5
Deferred income taxes and investment tax credits, net	88			139
Allowance for equity funds used during construction	(16		)	(24		)
Other	1			1
Changes in assets and liabilities:
Receivables	(51		)	(76		)
Materials and supplies	(26		)	3
Accounts and wages payable	(177		)	(151		)
Taxes accrued	243			(22		)
Regulatory assets and liabilities	101			(78		)
Assets, other	6			44
Liabilities, other	11			30
Pension and other postretirement benefits	15			(8		)
Net cash provided by operating activities	1,040			660
Cash Flows From Investing Activities:
Capital expenditures	(444		)	(548		)
Nuclear fuel expenditures	(30		)	(28		)
Purchases of securities – nuclear decommissioning trust fund	(301		)	(365		)
Sales and maturities of securities – nuclear decommissioning trust fund	290			354
Money pool advances, net	(250		)	—
Other	(4		)	(6		)
Net cash used in investing activities	(739		)	(593		)
Cash Flows From Financing Activities:
Dividends on common stock	(490		)	(268		)
Dividends on preferred stock	(3		)	(3		)
Short-term debt, net	(97		)	65
Money pool borrowings, net	—			(105		)
Maturities of long-term debt	(114		)	(104		)
Issuances of long-term debt	249			350
Capital contribution from parent	224			—
Capital issuance cost	(2		)	(2		)
Net cash used in financing activities	(233		)	(67		)
Net change in cash and cash equivalents	68			—
Cash and cash equivalents at beginning of year	1			1
Cash and cash equivalents at end of period	$	69		$	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,
	2015		2014		2015			2014
Operating Revenues:
Electric	$	540	$	445	$	1,316		$	1,162
Gas	115		127		597			703
Total operating revenues	655		572		1,913			1,865
Operating Expenses:
Purchased power	128		89		317			256
Gas purchased for resale	33		43		277			374
Other operations and maintenance	202		185		606			580
Depreciation and amortization	74		66		220			193
Taxes other than income taxes	29		31		101			109
Total operating expenses	466		414		1,521			1,512
Operating Income	189		158		392			353
Other Income and Expense:
Miscellaneous income	4		4		15			12
Miscellaneous expense	3		2		10			7
Total other income	1		2		5			5
Interest Charges	33		31		99			90
Income Before Income Taxes	157		129		298			268
Income Taxes	59		54		114			110
Net Income	98		75		184			158
Other Comprehensive Loss, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(1), $(1), $(2) and $(2), respectively	—		—		(2		)	(2		)
Comprehensive Income	$	98	$	75	$	182		$	156


Net Income	$	98	$	75	$	184		$	158
Preferred Stock Dividends	—		—		2			2
Net Income Available to Common Stockholder	$	98	$	75	$	182		$	156

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, 2015		December 31, 2014
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	1
Accounts receivable – trade (less allowance for doubtful accounts of $13 and $13, respectively)	229		212
Accounts receivable – affiliates	1		22
Unbilled revenue	86		119
Miscellaneous accounts receivable	11		9
Materials and supplies	174		177
Current regulatory assets	65		129
Current accumulated deferred income taxes, net	50		160
Other current assets	16		15
Total current assets	632		844
Property and Plant, Net	6,615		6,165
Investments and Other Assets:
Goodwill	411		411
Regulatory assets	922		883
Other assets	76		78
Total investments and other assets	1,409		1,372
TOTAL ASSETS	$	8,656	$	8,381
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	129	$	—
Short-term debt	—		32
Borrowings from money pool	122		15
Accounts and wages payable	251		207
Accounts payable – affiliates	36		50
Taxes accrued	7		17
Interest accrued	39		24
Customer deposits	70		77
Mark-to-market derivative liabilities	38		42
Current environmental remediation	35		52
Current regulatory liabilities	37		84
Other current liabilities	90		100
Total current liabilities	854		700
Long-term Debt, Net	2,112		2,241
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,412		1,408
Regulatory liabilities	728		703
Pension and other postretirement benefits	282		277
Environmental remediation	203		199
Other deferred credits and liabilities	224		192
Total deferred credits and other liabilities	2,849		2,779
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholders’ Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding	—		—
Other paid-in capital	1,980		1,980
Preferred stock	62		62
Retained earnings	793		611
Accumulated other comprehensive income	6		8
Total stockholders’ equity	2,841		2,661
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	8,656	$	8,381

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,
	2015			2014
Cash Flows From Operating Activities:
Net income	$	184		$	158
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	218			190
Amortization of debt issuance costs and premium/discounts	11			10
Deferred income taxes and investment tax credits, net	108			136
Other	(7		)	(6		)
Changes in assets and liabilities:
Receivables	45			80
Materials and supplies	3			(37		)
Accounts and wages payable	11			1
Taxes accrued	(10		)	(5		)
Regulatory assets and liabilities	(31		)	(135		)
Assets, other	7			6
Liabilities, other	(13		)	(4		)
Pension and other postretirement benefits	13			(12		)
Counterparty collateral, net	2			14
Net cash provided by operating activities	541			396
Cash Flows From Investing Activities:
Capital expenditures	(620		)	(633		)
Other	5			6
Net cash used in investing activities	(615		)	(627		)
Cash Flows From Financing Activities:
Dividends on preferred stock	(2		)	(2		)
Short-term debt, net	(32		)	189
Money pool borrowings, net	107			(40		)
Redemptions of long-term debt	—			(163		)
Issuances of long-term debt	—			248
Capital issuance costs	—			(2		)
Advances received for construction	—			1
Net cash provided by financing activities	73			231
Net change in cash and cash equivalents	(1		)	—
Cash and cash equivalents at beginning of year	1			1
Cash and cash equivalents at end of period	$	—		$	1

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, 2015

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

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


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


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

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

The operating results, assets, and liabilities of the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers have been presented separately as discontinued operations for all periods presented in this report. Unless otherwise stated, these notes to Ameren’s financial statements exclude discontinued operations for all periods presented. See Note 12 - Divestiture Transactions and Discontinued Operations in this report for additional information regarding the discontinued operations presentation and Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information regarding Ameren’s divestiture of New AER in December 2013.

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

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

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

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, 2015:



	Ameren Missouri			Ameren Illinois^(a)		Ameren
Balance at December 31, 2014	$	389		$	7	$	396
Liabilities incurred^(b)	3			—		3
Liabilities settled	(1		)	(c)		(1		)
Accretion in 2015^(d)	17			(c)		17
Change in estimates^(e)	182			(c)		182
Balance at September 30, 2015	$	590		$	7	$	597


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


(b)	Ameren and Ameren Missouri recorded a new ARO of $3 million related to the Callaway energy center’s dry spent fuel storage facility. See Note 10 - Callaway Energy Center for additional information.


(c)	Less than $1 million.


(d)	Accretion expense was recorded as an increase to regulatory assets.

(e)

The ARO increase resulted in a corresponding increase recorded to “Property and Plant, Net.” During 2015, Ameren and Ameren Missouri increased their AROs related to the decommissioning of the Callaway energy center by $99 million to reflect the 2015 cost study and funding analysis filed with the MoPSC, extension of the estimated operating life until 2044, and a reduction in the discount rate assumption. See Note 10 - Callaway Energy Center for additional information. In addition, as a result of new federal regulations, Ameren and Ameren Missouri recorded an increase of $79 million to their AROs associated with CCR storage facilities. See Note 9 - Commitments and Contingencies for additional information. Ameren and Ameren Missouri also increased their AROs by $4 million due to a change in the estimated retirement dates of the Meramec and Rush Island energy centers as a result of the MoPSC’s April 2015 electric rate order.

Stock-based Compensation

A summary of nonvested performance share units at September 30, 2015, and changes during the nine months ended September 30, 2015, under the 2006 Incentive Plan and the 2014 Incentive Plan are presented below:



	Number of Performance Share Units		Weighted-average Fair Value Per Performance Share Unit
Nonvested at January 1, 2015	1,162,377		$	35.35
Granted^(a)	569,892		52.88
Forfeitures	(1,944	)	34.75
Vested^(b)	(92,892	)	45.97
Nonvested at September 30, 2015	1,637,433		$	40.85


(a)	Performance share units granted to certain executive and nonexecutive officers and other eligible employees in 2015 under the 2014 Incentive Plan.


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

The fair value of each performance share unit awarded in 2015 under the 2014 Incentive Plan was determined to be $52.88, which was based on Ameren’s closing common share price of $46.13 at December 31, 2014, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total stockholder return for a three-year performance period relative to the designated peer group beginning January 1, 2015. The simulations can produce a greater fair value for the performance share unit than the 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 1.10%, volatility of 12% to 18% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.

Excise Taxes

Ameren Missouri and Ameren Illinois collect certain excise taxes from customers that are levied on the sale or distribution of natural gas and electricity. Excise taxes are levied on Ameren Missouri’s electric and natural gas businesses and on Ameren Illinois’ natural gas business and are recorded gross in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” on the statement of income or the statement of income and comprehensive income. Excise taxes for electric service in Illinois are levied on the customer and are therefore not included in Ameren Illinois’ revenues and expenses. The following table presents excise taxes recorded in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” for the three and nine months ended September 30, 2015 and 2014:



	Three Months				Nine Months
	2015		2014		2015		2014
Ameren Missouri	$	52	$	47	$	127	$	120
Ameren Illinois	9		9		42		46
Ameren	$	61	$	56	$	169	$	166

Uncertain Tax Positions

The following table presents the total amount of reserves for unrecognized tax benefits (detriments) related to uncertain tax positions as of September 30, 2015, and December 31, 2014:



	September 30, 2015		December 31, 2014
Ameren	$	—	$	54
Ameren Missouri	—		—
Ameren Illinois	—		(1		)

The following table presents the amount of reserves for unrecognized tax benefits, included in the table above, related to uncertain tax positions that, if recognized, would have impacted results of operations as of December 31, 2014:



	December 31, 2014
Ameren	$	52
Ameren Missouri	—
Ameren Illinois	(1		)

In June 2015, a settlement was reached with the IRS for the 2013 tax year. This settlement resolved the uncertain tax position associated with the final tax basis of New AER and the related tax benefit resulting from the divested merchant generation business. The settlement resulted in a reduction of Ameren’s unrecognized tax benefits of $53 million and an increase to net income from discontinued operations.

State income tax returns are generally subject to examination for a period of three years after filing. We do not currently have material state income tax issues under examination, administrative appeal, or litigation. The state impact of any federal changes remains subject to examination by various states for up to one year after formal notification to the states.

Earnings Per Share

Basic earnings per share is computed by dividing net income attributable to Ameren common stockholders 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 stockholders by the weighted-average number of diluted common shares outstanding during the period. Earnings per diluted share reflects the potential dilution that would occur if certain stock-based performance share units were settled. The number of performance share units assumed to be settled was 1.3 million and 1.2 million in the three and nine months ended September 30, 2015, respectively, and 1.7 million in both of 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, 2015 and 2014.

Accounting and Reporting Developments

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

Revenue from Contracts with Customers

In 2014, FASB issued authoritative accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP. The guidance requires an entity to recognize an amount of revenue for the transfer of promised goods or services to customers that reflects the consideration which the entity expects to be entitled to in exchange for those goods or services. The guidance also requires additional disclosures to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In August 2015, FASB deferred the effective date of this revenue standard to the first quarter of 2018, with an option for entities to early adopt in the first quarter of 2017. The guidance allows entities to choose one of two transition methods, either by applying the guidance retrospectively to each reporting period presented or by recording a cumulative effect adjustment to retained earnings in the period of initial adoption. The Ameren Companies are currently assessing the impacts of this guidance on their results of operations, financial positions and disclosures, as well as the transition method that they will use to adopt the guidance.

Presentation of Debt Issuance Costs

In April 2015, FASB issued authoritative accounting guidance to simplify the presentation of debt issuance costs. The guidance requires debt issuance costs to be presented in the balance sheet as a reduction to the associated debt liability. Currently, debt issuance costs are presented as a component of “Other assets” on the Ameren Companies’ balance sheets. As of September 30, 2015, Ameren, Ameren Missouri, and Ameren Illinois had debt issuance costs of $35 million, $15 million, and $19 million, respectively. The Ameren Companies expect to early adopt this standard in the fourth quarter of 2015. The guidance will be applied retrospectively, and will not affect the Ameren Companies' results of operations or cash flows.

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

2015 Electric Rate Order

The order approved Ameren Missouri’s request for continued use of the FAC; however, it changed the FAC to exclude all transmission revenues and substantially all transmission charges. In addition, the order did not approve the continued use of the regulatory tracking mechanisms for storm costs and vegetation management and infrastructure inspection costs. These changes to Ameren Missouri’s recovery mechanisms are expected to contribute to regulatory lag. The order did approve the continued use of the regulatory tracking mechanisms for pension and other postretirement benefits, renewable energy standard costs, solar rebates, and uncertain tax positions that the MoPSC authorized in prior electric rate orders.

In addition, the order approved a reduction to Noranda’s electric rates with an offsetting increase in electric rates for Ameren Missouri’s other customers. The rate shift is revenue neutral to Ameren Missouri.

In June 2015, Ameren Missouri filed an appeal with the Missouri Court of Appeals, Western District, of the reduction to Noranda’s electric rates included in the MoPSC’s order. The outcome of this appeal is not expected to impact Ameren Missouri’s results of operations, financial position, or liquidity.

MEEIA Filing

The MEEIA established a regulatory framework that, among other things, requires the MoPSC to ensure that a utility’s financial incentives are aligned to help customers use energy more efficiently, to provide timely cost recovery, and to provide earnings opportunities associated with cost-effective energy efficiency programs. Missouri does not have a law mandating energy efficiency programs.

In August 2012, the MoPSC approved Ameren Missouri’s customer energy efficiency programs, net shared benefits, and performance incentive for 2013 through 2015. The 2013 through 2015 plan anticipated Ameren Missouri would invest up to $147

million in customer energy efficiency programs, realize $100 million of net shared benefits, and be eligible for a performance incentive that would allow it the potential to earn additional revenues by achieving certain customer energy efficiency goals, including $19 million if 100% of the goals are achieved during the three-year period, with the potential to earn a larger performance incentive if Ameren Missouri’s energy savings exceed those goals. From January 2013 through September 2015, Ameren Missouri invested $110 million in customer energy efficiency programs and realized $134 million of net shared benefits. In June 2015, the MoPSC staff filed a complaint case with the MoPSC regarding the method and inputs used in calculating the performance incentive. If the MoPSC agrees with the MoPSC staff’s interpretation of the August 2012 MEEIA order, the performance incentive recognized in 2016 would be significantly less than the performance incentive calculated using Ameren Missouri’s interpretation. Ameren Missouri has not recorded revenues associated with the performance incentive. However, regardless of the MoPSC’s decision in the complaint case, Ameren Missouri believes it will exceed 100% of the customer energy efficiency goals, subject to MoPSC review, and therefore expects to recognize revenues of at least $19 million in 2016. There is no date by which the MoPSC must issue a decision in this complaint case.

In October 2015, the MoPSC rejected Ameren Missouri’s MEEIA energy efficiency plan for 2016 through 2018, which included a portfolio of customer energy efficiency programs along with a rider to collect the program costs, net shared benefits, and a performance incentive from customers. Ameren Missouri is studying the MoPSC’s October 2015 order and evaluating whether to file another proposed energy efficiency plan with the MoPSC.

Noranda Contract Notification

Ameren Missouri supplies electricity to Noranda’s aluminum smelter in southeast Missouri under a long-term power supply agreement. In May 2015, Ameren Missouri notified Noranda of its intent to terminate the agreement effective June 1, 2020. If Ameren Missouri wanted to cease providing electricity to Noranda, Ameren Missouri would also be required to obtain approval from the MoPSC. Sales to Noranda represented 5% of Ameren Missouri’s total electric revenue in 2014.

ATXI Transmission Projects

In May 2015, the MoPSC granted ATXI a certificate of convenience and necessity for the seven-mile portion of the Illinois Rivers project located in Missouri.

In June 2015, ATXI made a filing with the MoPSC requesting a certificate of convenience and necessity for the Mark Twain project. The Mark Twain project is a MISO-approved 100-mile transmission line located in northeast Missouri. A decision is expected from the MoPSC in 2016.

Illinois

IEIMA

Under the provisions of the IEIMA’s formula rate framework, which currently extends through 2019, Ameren Illinois’ electric delivery service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs. Throughout each year, Ameren Illinois records a regulatory asset or a regulatory liability and a corresponding increase or decrease to operating revenues for any differences between the revenue requirement reflected in customer rates for that year and its estimate of the probable increase or decrease in the revenue requirement expected to ultimately be approved by the ICC based on that year's actual recoverable costs incurred. As of September 30, 2015, Ameren Illinois had recorded regulatory assets of $52 million, $103 million, and $14 million, to reflect its expected 2015, 2014, and 2013 revenue requirement reconciliation adjustments, with interest, respectively. Ameren Illinois is collecting the 2013 revenue requirement reconciliation adjustment from customers during 2015.

Ameren Illinois’ annual electric delivery service formula rate update to establish customer rates for 2016 is currently pending before the ICC. If the ICC approves as filed, the annual update filing would result in a $109 million increase in Ameren Illinois’ electric delivery service revenue requirement, beginning in January 2016. This update reflects an increase to the annual formula rate based on 2014 actual recoverable costs and expected net plant additions for 2015, an increase to include the 2014 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the 2013 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2015. In October 2015, the ICC staff submitted its calculation of Ameren Illinois’ revenue requirement. The ICC staff recommended adjustments that would result in a $107 million increase in Ameren Illinois’ electric delivery service revenue

requirement. An ICC decision on this update filing is required by December 2015.

2015 Natural Gas Delivery Service Rate Case

In January 2015, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service. In an attempt to reduce regulatory lag, Ameren Illinois used a 2016 future test year in this proceeding. Additionally, the request included a proposal to implement a volume balancing adjustment for residential and small nonresidential customers. The volume balancing adjustment would increase or decrease revenues as weather deviates from normal conditions to ensure that weather-related changes in natural gas sales volumes do not result in an over or under collection of natural gas revenues for these rate classes. This case includes a capital structure composed of 50% common equity and a rate base of $1.2 billion. In July 2015, Ameren Illinois, the ICC staff, and certain other intervenors filed a stipulation and agreement with the ICC that would result in rates that are based on a return on common equity of 9.6%. The agreement does not address the positions of all of the parties in the rate case. Based on the terms in the agreement and the unresolved positions in the case, Ameren Illinois' request seeks an annual revenue increase of $45 million, which is consistent with the ICC staff’s recommendation and the administrative law judges' proposed order issued in November 2015. The administrative law judges' order also proposed the approval of the volume balancing adjustment.

A decision by the ICC in this proceeding is required by December 2015, with new rates expected to be effective in January 2016. Ameren Illinois cannot predict the level of any delivery service rate changes the ICC may approve, whether the ICC will approve the volume balancing adjustment, or if the ICC will approve the agreement between Ameren Illinois, the ICC staff, and certain other intervenors. In addition, Ameren Illinois cannot predict whether any rate changes that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and to earn a reasonable return on investments when the rate changes go into effect.

2015 ICC Purchased Power Reconciliation

In January 2015, the ICC issued an order that approved Ameren Illinois' reconciliation of revenues collected under its purchased power rider mechanism and Ameren Illinois' related cumulative power usage cost. In the first quarter of 2015, based on the January 2015 order, both Ameren and Ameren Illinois recorded a $15 million increase to electric revenues for the recovery of this cumulative power usage cost from electric customers.

ATXI Transmission Project

The Spoon River project is a MISO-approved 46-mile transmission line to be constructed in northwest Illinois. In September 2015, the ICC granted a certificate of public convenience and necessity and project approval for the Spoon River project.

Federal

Ameren Illinois Electric Transmission Rate Refund

In July 2012, the FERC issued an order concluding that Ameren Illinois improperly included acquisition premiums, including goodwill, in determining the common equity used in its electric transmission formula rate and thereby inappropriately recovered a higher amount from its electric transmission customers. The order required Ameren Illinois to make refunds to customers for such improperly included amounts.

In July 2015, the FERC approved a settlement agreement between Ameren Illinois and the affected customers. The settlement agreement required Ameren Illinois to make refunds and payments of $8 million to electric transmission customers, all of which was paid by September 30, 2015. The settlement agreement also requires Ameren Illinois to take other actions, such as reducing common equity for electric transmission ratemaking purposes on a prospective basis.

FERC Complaint Cases

In November 2013, a customer group filed a complaint case with the FERC seeking a reduction in the allowed base return on common equity for the FERC-regulated MISO transmission rate base under the MISO tariff to 9.15%. Currently, the FERC-allowed base return on common equity for MISO transmission owners is 12.38%. The FERC scheduled the case for hearing proceedings, requiring a proposed order from its administrative law judge to be issued no later than November 30, 2015, which will subsequently require FERC approval. The FERC has previously utilized a calculation to establish the allowed base return on common equity, which requires multiple inputs based on observable market data specific to the utility industry and broader macroeconomic data spanning unique time periods for each return on equity complaint case. We expect observable market data for the six months ended February 11, 2015, will be used in the November 2013 complaint case. As the maximum FERC-allowed refund period for the November 2013 complaint case ended in February 2015, another customer complaint case was filed in February 2015. The February 2015 complaint case seeks a reduction in the allowed base return on common equity for the FERC-regulated MISO transmission rate base under the MISO tariff to 8.67%. The FERC scheduled the February 2015 complaint case for hearing proceedings, requiring a proposed order from its administrative law judge to be issued no later than June 30, 2016, which will subsequently require FERC approval. We expect observable market data for the six months ended December 31, 2015, will be used in the February 2015 complaint case.

As of September 30, 2015, Ameren and Ameren Illinois had current regulatory liabilities of $36 million and $25 million, respectively, representing their estimates of the potential refunds from the November 12, 2013 refund effective date. Ameren’s and Ameren Illinois’ recorded liabilities reflect their interpretation of the method and inputs used in the FERC’s calculation to establish the allowed base return on common equity, based on observable market data for the six months ended February 11,

2015, with respect to the November 2013 complaint case refund period, and based on observable market data through September 30, 2015, with respect to the February 2015 complaint case refund period. Ameren’s and Ameren Illinois’ liabilities also reflect the incentive adder discussed below, which became effective in early January 2015. Ameren Missouri did not record a liability as of September 30, 2015, and does not expect that a reduction in the FERC-allowed base return on common equity for MISO transmission owners would be material to its results of operations, financial position, or liquidity. A 50 basis point reduction in the FERC-allowed return on common equity would reduce Ameren's and Ameren Illinois' annual earnings by an estimated $4 million and $2 million, respectively, based on 2015 projected rate base.

On January 6, 2015, a FERC-approved incentive adder of up to 50 basis points on the allowed base return on common equity for our participation in an RTO became effective. Upon the issuance of the final order addressing the initial MISO complaint case, beginning with its January 6, 2015 effective date, the incentive adder will reduce any refund to customers relating to a reduction of the base return on common equity.

Combined Construction and Operating License

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

NOTE 3 - SHORT-TERM DEBT AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash, drawings under committed credit agreements, commercial paper issuances, or, in the case of Ameren Missouri and Ameren Illinois, short-term intercompany borrowings.

The 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement, both of which expire on December 11, 2019, were not utilized for direct borrowings during the nine months ended September 30, 2015, but were used to support commercial paper issuances and to issue letters of credit. Based on letters of credit issued under the 2012 Credit Agreements, as well as commercial paper outstanding, the aggregate amount of credit capacity available under the 2012 Credit Agreements to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, at September 30, 2015, was $1.3 billion.

Commercial Paper

The following table presents commercial paper outstanding at Ameren (parent), Ameren Missouri, and Ameren Illinois as of September 30, 2015, and December 31, 2014:



	September 30, 2015		December 31, 2014
Ameren (parent)	$	783	$	585
Ameren Missouri	—		97
Ameren Illinois	—		32
Ameren Consolidated	$	783	$	714

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, 2015 and 2014:



	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated
2015
Average daily commercial paper outstanding	$	770		$	56		$	6		$	832
Weighted-average interest rate	0.56		%	0.50		%	0.44		%	0.56		%
Peak commercial paper during period^(a)	$	874		$	294		$	48		$	1,108
Peak interest rate	0.70		%	0.60		%	0.60		%	0.70		%
2014
Average daily commercial paper outstanding	$	386		$	141		$	157		$	609
Weighted-average interest rate	0.36		%	0.38		%	0.31		%	0.35		%
Peak commercial paper during period^(a)	$	531		$	495		$	300		$	907
Peak interest rate	0.75		%	0.70		%	0.34		%	0.75		%


(a)	The timing of peak commercial paper issuances varies by company, and therefore the peak amounts presented by company might not equal the Ameren Consolidated peak commercial paper issuances for the period.

Indebtedness Provisions and Other Covenants

The information below is a summary of the Ameren Companies’ compliance with financial covenants in the 2012 Credit Agreements. See Note 4 - Short-term Debt and Liquidity under Part II, Item 8, in the Form 10-K for a detailed description of these provisions. The 2012 Credit Agreements also contain nonfinancial covenants, including restrictions on the ability to incur liens, to transact with affiliates, to dispose of assets, to make investments in or transfer assets to its affiliates, and to merge with other entities.

The 2012 Credit Agreements require each of Ameren, Ameren Missouri, and Ameren Illinois to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of September 30, 2015, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the 2012 Credit Agreements, were 50%, 48%, and 46%, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. In addition, under the 2012 Illinois Credit Agreement and, by virtue of the cross-default provisions of the 2012 Missouri Credit Agreement, under the 2012 Missouri Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of at least 2.0 to 1.0. However, the interest coverage requirement only applies at such times as Ameren does not have a senior long-term unsecured credit rating of at least Baa3 from Moody’s or BBB- from S&P. As of September 30, 2015, Ameren exceeded the rating requirements; therefore, the interest coverage requirement was not applicable. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2012 Credit Agreement.

The 2012 Credit Agreements contain default provisions that apply separately to each borrower; provided, however, that a default of Ameren Missouri or Ameren Illinois under the applicable 2012 Credit Agreement will also be deemed to constitute a default of Ameren under such agreement. Defaults include a cross-default of such borrower under any other agreement covering outstanding indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and nonmaterial subsidiaries) in excess of $75 million in the aggregate (including under the other 2012 Credit Agreement). However, under the default provisions of the 2012 Credit Agreements, any default of Ameren under any 2012 Credit

Agreement that results solely from a default of Ameren Missouri or Ameren Illinois thereunder does not result in a cross-default of Ameren under the other 2012 Credit Agreement. Further, the 2012 Credit Agreement default provisions provide that an Ameren default under any of the 2012 Credit Agreements does not constitute a default by Ameren Missouri or Ameren Illinois.

None of the Ameren Companies' credit agreements or financing arrangements contain credit rating triggers that would cause a default or acceleration of repayment of outstanding balances. The Ameren Companies were in compliance with the covenants in their credit agreements at September 30, 2015.

Money Pools

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

Ameren Missouri, Ameren Illinois, and ATXI may participate in the utility money pool as both lenders and borrowers. Ameren and Ameren Services may participate in the utility money pool only as lenders. Surplus internal funds are contributed to the utility money pool from participants. The primary sources of external funds for the utility money pool are the 2012 Credit Agreements and the commercial paper programs. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. Participants receiving a loan under the utility money pool must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing and lending under the utility money pool for the three and nine months ended September 30, 2015, was 0.10% and 0.09%, respectively (2014 - 0.10% and 0.23%, 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, 2015 and 2014.

NOTE 4 - LONG-TERM DEBT AND EQUITY

Ameren Missouri

In March 2015, Ameren Missouri received cash capital contributions of $224 million from Ameren (parent).

In April 2015, Ameren Missouri issued $250 million of 3.65% senior secured notes due April 15, 2045, with interest payable semiannually on April 15 and October 15 of each year, beginning October 15, 2015. Ameren Missouri received proceeds of $247 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Missouri incurred in connection with the repayment of $114 million of its 4.75% senior secured notes that matured on April 1, 2015.

Indenture Provisions and Other Covenants

Ameren Missouri’s and Ameren Illinois’ indentures, credit facilities, and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions, but would restrict the companies’ ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios and dividend coverage ratios, and bonds and preferred stock issuable as of September 30, 2015, at an assumed annual interest rate of 5% and dividend rate of 6%.



	Required Interest Coverage Ratio^(a)	Actual Interest Coverage Ratio		Bonds Issuable^(b)		Required Dividend Coverage Ratio^(c)	Actual Dividend Coverage Ratio		Preferred Stock Issuable
Ameren Missouri	≥2.0	3.7	$	3,338		≥2.5	99.3	$	2,206
Ameren Illinois	≥2.0	7.0		3,659	^(d)	≥1.5	3.0		203	^(e)


(a)	Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.


(b)	Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $946 million and $204 million at Ameren Missouri and Ameren Illinois, respectively.


(c)	Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation.


(d)	Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture. The amount of bonds issuable by Ameren Illinois is also subject to the lien restrictions contained in the 2012 Illinois Credit Agreement.


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

Ameren Missouri and Ameren Illinois and certain other Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from retained earnings. In addition, under Illinois law, Ameren Illinois may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.

Ameren Illinois’ articles of incorporation require dividend payments on its common stock to be based on ratios of common stock to total capitalization and other provisions related to certain

operating expenses and accumulations of earned surplus. Ameren Illinois committed to the FERC to maintain a minimum of 30% equity in its capital structure. As of September 30, 2015, Ameren Illinois had 52% equity in its capital structure.

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

Off-Balance-Sheet Arrangements

At September 30, 2015, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future. See Note 12 - Divestiture Transactions and Discontinued Operations for Ameren (parent) guarantees and letters of credit issued to support New AER based on the transaction agreement with IPH.

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, 2015 and 2014:



	Three Months				Nine Months
	2015		2014		2015		2014
Ameren:^(a)
Miscellaneous income:
Allowance for equity funds used during construction	$	8	$	10	$	19	$	26
Interest income on industrial development revenue bonds	7		6		20		20
Interest income	4		3		12		8
Other	—		2		3		6
Total miscellaneous income	$	19	$	21	$	54	$	60
Miscellaneous expense:
Donations	$	—	$	3	$	10	$	9
Other	5		4		12		11
Total miscellaneous expense	$	5	$	7	$	22	$	20
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction	$	7	$	9	$	16	$	24
Interest income on industrial development revenue bonds	7		6		20		20
Interest income	—		—		1		1
Total miscellaneous income	$	14	$	15	$	37	$	45
Miscellaneous expense:
Donations	$	—	$	2	$	3	$	5
Other	3		2		5		5
Total miscellaneous expense	$	3	$	4	$	8	$	10
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	1	$	1	$	3	$	2
Interest income	3		2		10		5
Other	—		1		2		5
Total miscellaneous income	$	4	$	4	$	15	$	12
Miscellaneous expense:
Donations	$	—	$	—	$	4	$	3
Other	3		2		6		4
Total miscellaneous expense	$	3	$	2	$	10	$	7


(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, 2015, and December 31, 2014. As of September 30, 2015, these contracts ran through October 2017, March 2021, May 2032, and December 2016 for fuel oils, natural gas, power, and uranium, respectively.



	Quantity (in millions, except as indicated)
	2015			2014
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)^(a)	33	(b)	33	50	(b)	50
Natural gas (in mmbtu)	30	152	182	28	108	136
Power (in megawatthours)	1	10	11	1	11	12
Uranium (pounds in thousands)	299	(b)	299	332	(b)	332


(a)	Fuel oils consist of heating oil and ultra-low-sulfur diesel.


(b)	Not applicable.

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

If we determine that a contract meets the definition of a derivative and does not qualify for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives 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 regulatory liabilities in the period in which the change occurs. We

believe derivative losses and gains deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through future rates charged to customers. Regulatory assets and regulatory 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, 2015, and December 31, 2014, all contracts that qualify for hedge accounting received regulatory deferral.

Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under a master netting arrangement or similar agreement. The Ameren Companies did not elect to adopt this guidance for any eligible derivative instruments.

The following table presents the carrying value and balance sheet location of all derivative instruments, none of which were designated as hedging instruments under hedge accounting, as of September 30, 2015, and December 31, 2014:



	Balance Sheet Location	Ameren Missouri		Ameren Illinois		Ameren
2015
Natural gas	Other current assets	$	1	$	—	$	1
Power	Other current assets	22		—		22
	Other assets	1		—		1
	Total assets	$	24	$	—	$	24
Fuel oils	Other current liabilities	$	19	$	—	$	19
	Other deferred credits and liabilities	6		—		6
Natural gas	MTM derivative liabilities	(a)		26		(a)
	Other current liabilities	5		—		31
	Other deferred credits and liabilities	9		18		27
Power	MTM derivative liabilities	(a)		12		(a)
	Other current liabilities	1		—		13
	Other deferred credits and liabilities	—		158		158
Uranium	Other current liabilities	1		—		1
	Total liabilities	$	41	$	214	$	255
2014
Fuel oils	Other current assets	$	2	$	—	$	2
Natural gas	Other current assets	1		1		2
Power	Other current assets	15		—		15
	Total assets	$	18	$	1	$	19
Fuel oils	Other current liabilities	$	22	$	—	$	22
	Other deferred credits and liabilities	7		—		7
Natural gas	MTM derivative liabilities	(a)		31		(a)
	Other current liabilities	6		—		37
	Other deferred credits and liabilities	6		13		19
Power	MTM derivative liabilities	(a)		11		(a)
	Other current liabilities	3		—		14
	Other deferred credits and liabilities	—		131		131
Uranium	Other current liabilities	2		—		2
	Total liabilities	$	46	$	186	$	232


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

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments deferred in regulatory assets or regulatory liabilities as of September 30, 2015, and December 31, 2014:



	Ameren Missouri			Ameren Illinois			Ameren
2015
Fuel oils derivative contracts^(a)	$	(25	)	$	—		$	(25	)
Natural gas derivative contracts^(b)	(13		)	(44		)	(57		)
Power derivative contracts^(c)	22			(170		)	(148		)
Uranium derivative contracts^(d)	(1		)	—			(1		)
2014
Fuel oils derivative contracts	$	(29	)	$	—		$	(29	)
Natural gas derivative contracts	(11		)	(43		)	(54		)
Power derivative contracts	12			(142		)	(130		)
Uranium derivative contracts	(2		)	—			(2		)


(a)	Represents net losses associated with fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s rail transportation surcharges for coal through December 2017. Losses deferred as current regulatory assets include $19 million at Ameren and Ameren Missouri.

(b)

Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through March 2021 at Ameren and Ameren Missouri and through October 2019 at Ameren Illinois. Gains deferred as current regulatory liabilities include $1 million at Ameren and Ameren Missouri. Losses deferred as current regulatory assets include $31 million, $5 million, and $26 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively.

(c)

Represents net gains (losses) associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren Illinois and through December 2016 at Ameren Missouri. Gains deferred as current regulatory liabilities include $22 million at Ameren and Ameren Missouri. Losses deferred as current regulatory assets include $13 million, $1 million, and $12 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively.


(d)	Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through January 2017. Losses deferred as current regulatory assets include $1 million at Ameren and Ameren Missouri.

Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master netting arrangements or similar agreements, and reporting daily exposure to senior management.

We believe that entering into master netting arrangements or similar agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master netting arrangements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master netting arrangements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at the master netting arrangement or similar agreement level by counterparty.

The following table provides the recognized gross derivative balances and the net amounts of those derivatives subject to an enforceable master netting arrangement or similar agreement as of September 30, 2015, and December 31, 2014:



			Gross Amounts Not Offset in the Balance Sheet
Commodity Contracts Eligible to be Offset	Gross Amounts Recognized in the Balance Sheet		Derivative Instruments		Cash Collateral Received/Posted^(a)		Net Amount
2015
Assets:
Ameren Missouri	$	24	$	2	$	—	$	22
Ameren Illinois	—		—		—		—
Ameren	$	24	$	2	$	—	$	22
Liabilities:
Ameren Missouri	$	41	$	2	$	6	$	33
Ameren Illinois	214		—		1		213
Ameren	$	255	$	2	$	7	$	246
2014
Assets:
Ameren Missouri	$	18	$	5	$	—	$	13
Ameren Illinois	1		—		—		1
Ameren	$	19	$	5	$	—	$	14
Liabilities:
Ameren Missouri	$	46	$	5	$	5	$	36
Ameren Illinois	186		—		—		186
Ameren	$	232	$	5	$	5	$	222


(a)	Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current assets” and “Other assets” on the balance sheet.

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into groupings according to the primary business in which each engages. We calculate maximum exposures based on the gross fair value of financial instruments, including NPNS and other accrual contracts. These exposures are presented on a gross basis, which include affiliate exposure not eliminated at the consolidated Ameren level. As of September 30, 2015, if counterparty groups were to fail completely to perform on contracts, Ameren, Ameren Missouri, and Ameren Illinois' maximum exposures were $12 million, $12 million, and $- million, respectively. The potential loss on counterparty exposures may be reduced or eliminated by the application of master netting arrangements or similar agreements and collateral held. As of September 30, 2015, the potential loss after consideration of the application of master netting arrangements or similar agreements and collateral held for Ameren, Ameren Missouri, and Ameren Illinois was $11 million, $11 million, and $- million, respectively.

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of September 30, 2015, 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 could be required to be posted with counterparties. 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, 2015, 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)
2015
Ameren Missouri	$	88	$	7	$	75
Ameren Illinois	82		1		75
Ameren	$	170	$	8	$	150


(a)	Prior to 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 exchange 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 for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of September 30, 2015:



		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Weighted Average
Level 3 Derivative asset and liability - commodity contracts^(a):
Ameren	Fuel oils	$	—	$	(1	)	Option model	Volatilities(%)^(e)	63	(d)
							Discounted cash flow	Ameren Missouri credit risk(%)^(b)(c)	0.40	(d)
	Natural gas	—		(1		)	Option model	Volatilities(%)^(e)	20 - 44	33
								Nodal basis($/mmbtu)^(b)	(0.30) - (0.10)	(0.20)
							Discounted cash flow	Nodal basis($/mmbtu)^(e)	(1.40) - 0.10	(0.20)
								Counterparty credit risk(%)^(b)(c)	0.40 - 12.07	6.60
								Ameren Missouri credit risk(%)^(b)(c)	0.40	(d)
	Power^(f)	23		(171		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)^(g)	26 - 40	29
								Estimated auction price for FTRs($/MW)^(e)	(480) - 2,333	193
								Nodal basis($/MWh)^(e)	(10) - (1)	(3)
								Counterparty credit risk(%)^(b)(c)	0.46 - 0.84	0.73
								Ameren Illinois credit risk(%)^(b)(c)	0.40	(d)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)^(e)	3 - 4	4
								Escalation rate(%)^(e)(h)	2 - 3	2
							Contract price allocation	Estimated renewable energy credit costs($/credit)^(e)	5 - 7	6
	Uranium	—		(1		)	Discounted cash flow	Average forward uranium pricing($/pound)^(e)	37 - 39	37
Ameren Missouri	Fuel oils	$	—	$	(1	)	Option model	Volatilities(%)^(e)	63	(d)
							Discounted cash flow	Ameren Missouri credit risk(%)^(b)(c)	0.40	(d)
	Natural gas	—		(1		)	Option model	Volatilities(%)^(e)	20 - 44	33
								Nodal basis($/mmbtu)^(b)	(0.30) - (0.10)	(0.20)
							Discounted cash flow	Nodal basis($/mmbtu)^(e)	(1.40) - 0.10	(0.20)
								Counterparty credit risk(%)^(b)(c)	0.40 - 12.07	6.60
								Ameren Missouri credit risk(%)^(b)(c)	0.40	(d)
	Power^(f)	23		(1		)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)^(b)	26 - 40	34
								Estimated auction price for FTRs($/MW)^(e)	(480) - 2,333	193
								Nodal basis($/MWh)^(b)	(10) - (5)	(9)
								Counterparty credit risk(%)^(b)(c)	0.46 - 0.84	0.73
	Uranium	—		(1		)	Discounted cash flow	Average forward uranium pricing($/pound)^(e)	37 - 39	37
Ameren Illinois	Power^(f)	$	—	$	(170	)	Discounted cash flow	Average forward peak and off-peak pricing - forwards/swaps($/MWh)^(e)	27 - 33	30
								Nodal basis($/MWh)^(e)	(6) - (1)	(3)
								Ameren Illinois credit risk(%)^(b)(c)	0.40	(d)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)^(e)	3 - 4	4
								Escalation rate(%)^(e)(h)	2 - 3	2
							Contract price allocation	Estimated renewable energy credit costs($/credit)^(e)	5 - 7	6


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


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


(c)	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.


(d)	Not applicable.


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


(f)	Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2019. Valuations beyond 2019 use fundamentally modeled pricing by month for peak and off-peak demand.


(g)	The balance at Ameren is comprised of Ameren Missouri and Ameren Illinois power contracts, which respond differently to unobservable input changes due to their opposing positions. As such, refer to the power sensitivity analysis for each company above.


(h)	Escalation rate applies to power prices 2026 and beyond.



		Fair Value								Weighted
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Average
Level 3 Derivative asset and liability – commodity contracts^(a):
Ameren	Fuel oils	$	2	$	(8	)	Option model	Volatilities(%)^(b)	3 - 39	32
							Discounted cash flow	Ameren Missouri credit risk(%)^(b)(c)	0.43	(d)
								Escalation rate(%)^(e)(f)	5	(d)
	Natural Gas	1		(2		)	Option model	Volatilities(%)^(b)	31 - 144	63
								Nodal basis($/mmbtu)^(e)	(0.40) - 0	(0.20)
							Discounted cash flow	Nodal basis($/mmbtu)^(e)	(0.40) - 0.10	(0.20)
								Counterparty credit risk(%)^(b)(c)	0.43 - 13	3
								Ameren Missouri and Ameren Illinois credit risk(%)^(b)(c)	0.43	(d)
	Power^(g)	11		(144		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps($/MWh)^(h)	27 - 50	32
								Estimated auction price for FTRs($/MW)^(e)	(1,833) - 2,743	171
								Nodal basis($/MWh)^(e)	(6) - 0	(2)
								Counterparty credit risk(%)^(b)(c)	0.26	(d)
								Ameren Missouri and Ameren Illinois credit risk(%)^(b)(c)	0.43	(d)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)^(e)	4 - 5	4
								Escalation rate(%)^(e)(i)	0 - 1	1
							Contract price allocation	Estimated renewable energy credit costs($/credit)^(e)	5 - 7	6
	Uranium	—		(2		)	Discounted cash flow	Average forward uranium pricing($/pound)^(e)	35 - 40	36
Ameren Missouri	Fuel oils	$	2	$	(8	)	Option model	Volatilities(%)^(b)	3 - 39	32
							Discounted cash flow	Ameren Missouri credit risk(%)^(b)(c)	0.43	(d)
								Escalation rate(%)^(e)(f)	5	(d)
	Natural Gas	—		(1		)	Option model	Volatilities(%)^(b)	31 - 144	53
								Nodal basis($/mmbtu)^(e)	(0.40) - 0	(0.30)
							Discounted cash flow	Nodal basis($/mmbtu)^(e)	(0.10)	(d)
								Counterparty credit risk(%)^(b)(c)	0.57 - 13	5
								Ameren Missouri credit risk(%)^(b)(c)	0.43	(d)
	Power^(g)	11		(2		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps($/MWh)^(b)	27 - 50	32
								Estimated auction price for FTRs($/MW)^(e)	(1,833) - 2,743	171
								Counterparty credit risk(%)^(b)(c)	0.26	(d)
								Ameren Missouri credit risk(%)^(b)(c)	0.43	(d)
	Uranium	—		(2		)	Discounted cash flow	Average forward uranium pricing($/pound)^(e)	35 - 40	36
Ameren Illinois	Natural Gas	$	1	$	(1	)	Option model	Volatilities(%)^(b)	50 - 144	94
								Nodal basis($/mmbtu)^(e)	(0.10) - 0	(0.10)
							Discounted cash flow	Nodal basis($/mmbtu)^(e)	(0.40) - 0.10	(0.20)
								Counterparty credit risk(%)^(b)(c)	0.43 - 2	0.83
								Ameren Illinois credit risk(%)^(b)(c)	0.43	(d)
	Power^(g)	—		(142		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps($/MWh)^(e)	27 - 38	32
								Nodal basis($/MWh)^(e)	(6) - 0	(2)
								Ameren Illinois credit risk(%)^(b)(c)	0.43	(d)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)^(e)	4 - 5	4
								Escalation rate(%)^(e)(i)	0 - 1	1
							Contract price allocation	Estimated renewable energy credit costs($/credit)^(e)	5 - 7	6


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


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


(c)	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.


(d)	Not applicable.


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


(f)	Escalation rate applies to fuel oil prices 2017 and beyond.


(g)	Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2018. Valuations beyond 2018 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. As such, refer to the power sensitivity analysis for each company above.


(i)	Escalation rate applies to power prices 2026 and beyond.

In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing, as well as any potential credit enhancements, into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. No gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri, or Ameren Illinois in the first nine months of 2015 or 2014. At September 30, 2015, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $1 million, less than $1 million, and $1 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively. At December 31, 2014, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $1 million, less than $1 million, and $1 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively.

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, 2015:



		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
Ameren	Derivative assets - commodity contracts^(a):
	Natural gas	—		1		—		1
	Power	—		—		23		23
	Total derivative assets - commodity contracts	$	—	$	1	$	23	$	24
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	3	$	—	$	—	$	3
	Equity securities:
	U.S. large capitalization	338		—		—		338
	Debt securities:
	Corporate bonds	—		61		—		61
	U.S. treasury and agency securities	—		109		—		109
	Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	341	$	194	$	—	$	535	^(b)
	Total Ameren	$	341	$	195	$	23	$	559
Ameren	Derivative assets - commodity contracts^(a):
Missouri	Natural gas	—		1		—		1
	Power	—		—		23		23
	Total derivative assets - commodity contracts	$	—	$	1	$	23	$	24
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	3	$	—	$	—	$	3
	Equity securities:
	U.S. large capitalization	338		—		—		338
	Debt securities:
	Corporate bonds	—		61		—		61
	U.S. treasury and agency securities	—		109		—		109
	Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	341	$	194	$	—	$	535	^(b)
	Total Ameren Missouri	$	341	$	195	$	23	$	559
Liabilities:
Ameren	Derivative liabilities - commodity contracts^(a):
	Fuel oils	$	24	$	—	$	1	$	25
	Natural gas	1		56		1		58
	Power	—		—		171		171
	Uranium	—		—		1		1
	Total Ameren	$	25	$	56	$	174	$	255
Ameren	Derivative liabilities - commodity contracts^(a):
Missouri	Fuel oils	$	24	$	—	$	1	$	25
	Natural gas	1		12		1		14
	Power	—		—		1		1
	Uranium	—		—		1		1
	Total Ameren Missouri	$	25	$	12	$	4	$	41
Ameren	Derivative liabilities - commodity contracts^(a):
Illinois	Natural gas	$	—	$	44	$	—	$	44
	Power	—		—		170		170
	Total Ameren Illinois	$	—	$	44	$	170	$	214


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


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

The following table 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, 2014:



		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	$	2
	Natural gas	—		1		1		2
	Power	—		4		11		15
	Total derivative assets - commodity contracts	$	—	$	5	$	14	$	19
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	364		—		—		364
	Debt securities:
	Corporate bonds	—		63		—		63
	U.S. treasury and agency securities	—		102		—		102
	Other	—		17		—		17
	Total nuclear decommissioning trust fund	$	365	$	182	$	—	$	547	^(b)
	Total Ameren	$	365	$	187	$	14	$	566
Ameren	Derivative assets - commodity contracts^(a):
Missouri	Fuel oils	$	—	$	—	$	2	$	2
	Natural gas	—		1		—		1
	Power	—		4		11		15
	Total derivative assets - commodity contracts	$	—	$	5	$	13	$	18
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	364		—		—		364
	Debt securities:
	Corporate bonds	—		63		—		63
	U.S. treasury and agency securities	—		102		—		102
	Other	—		17		—		17
	Total nuclear decommissioning trust fund	$	365	$	182	$	—	$	547	^(b)
	Total Ameren Missouri	$	365	$	187	$	13	$	565
Ameren	Derivative assets - commodity contracts^(a):
Illinois	Natural gas	$	—	$	—	$	1	$	1
Liabilities:
Ameren	Derivative liabilities - commodity contracts^(a):
	Fuel oils	$	21	$	—	$	8	$	29
	Natural gas	1		53		2		56
	Power	—		1		144		145
	Uranium	—		—		2		2
	Total Ameren	$	22	$	54	$	156	$	232
Ameren	Derivative liabilities - commodity contracts^(a):
Missouri	Fuel oils	$	21	$	—	$	8	$	29
	Natural gas	1		10		1		12
	Power	—		1		2		3
	Uranium	—		—		2		2
	Total Ameren Missouri	$	22	$	11	$	13	$	46
Ameren	Derivative liabilities - commodity contracts^(a):
Illinois	Natural gas	$	—	$	43	$	1	$	44
	Power	—		—		142		142
	Total Ameren Illinois	$	—	$	43	$	143	$	186


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


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

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



		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at July 1, 2015	$	(1	)	$	(a)		$	(1	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(1	)		(a)			(1	)
Settlements		1			(a)			1
Ending balance at September 30, 2015	$	(1	)	$	(a)		$	(1	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2015	$	—		$	(a)		$	—
Natural gas:
Beginning balance at July 1, 2015	$	—		$	(1	)	$	(1	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(1	)		1			—
Ending balance at September 30, 2015	$	(1	)	$	—		$	(1	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2015	$	—		$	—		$	—
Power:
Beginning balance at July 1, 2015	$	27		$	(165	)	$	(138	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		2			(8	)		(6	)
Settlements		(7	)		3			(4	)
Ending balance at September 30, 2015	$	22		$	(170	)	$	(148	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2015	$	1		$	(7	)	$	(6	)
Uranium:
Beginning balance at July 1, 2015	$	(2	)	$	(a)		$	(2	)
Settlements		1			(a)			1
Ending balance at September 30, 2015	$	(1	)	$	(a)		$	(1	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2015	$	—		$	(a)		$	—


(a)	Not applicable.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended September 30, 2014:



		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at July 1, 2014	$	2		$	(a)		$	2
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(2	)		(a)			(2	)
Ending balance at September 30, 2014	$	—		$	(a)		$	—
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	(2	)	$	(a)		$	(2	)
Natural gas:
Beginning balance at July 1, 2014	$	—		$	—		$	—
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			1			1
Ending balance at September 30, 2014	$	—		$	1		$	1
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	—		$	—		$	—
Power:
Beginning balance at July 1, 2014	$	15		$	(103	)	$	(88	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(5	)		(23	)		(28	)
Settlements		(5	)		2			(3	)
Ending balance at September 30, 2014	$	5		$	(124	)	$	(119	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	(6	)	$	(22	)	$	(28	)
Uranium:
Beginning balance at July 1, 2014	$	(7	)	$	(a)		$	(7	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		3			(a)			3
Settlements		1			(a)			1
Ending balance at September 30, 2014	$	(3	)	$	(a)		$	(3	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	3		$	(a)		$	3


(a)	Not applicable.

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



		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2015	$	(6	)	$	(a)		$	(6	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(1	)		(a)			(1	)
Settlements		4			(a)			4
Transfers out of Level 3		2			(a)			2
Ending balance at September 30, 2015	$	(1	)	$	(a)		$	(1	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2015	$	—		$	(a)		$	—
Natural gas:
Beginning balance at January 1, 2015	$	(1	)	$	—		$	(1	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(1	)		1			—
Settlements		1			(1	)		—
Ending balance at September 30, 2015	$	(1	)	$	—		$	(1	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2015	$	—		$	—		$	—
Power:
Beginning balance at January 1, 2015	$	9		$	(142	)	$	(133	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			(37	)		(37	)
Purchases		29			—			29
Settlements		(16	)		9			(7	)
Ending balance at September 30, 2015	$	22		$	(170	)	$	(148	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2015	$	1		$	(35	)	$	(34	)
Uranium:
Beginning balance at January 1, 2015	$	(2	)	$	(a)		$	(2	)
Settlements		1			(a)			1
Ending balance at September 30, 2015	$	(1	)	$	(a)		$	(1	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2015	$	—		$	(a)		$	—


(a)	Not applicable.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2014:



		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2014	$	5		$	(a)		$	5
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(3	)		(a)			(3	)
Settlements		(2	)		(a)			(2	)
Ending balance at September 30, 2014	$	—		$	(a)		$	—
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	(2	)	$	(a)		$	(2	)
Natural gas:
Beginning balance at January 1, 2014	$	—		$	—		$	—
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			1			1
Purchases		—			(1	)		(1	)
Settlements		—			1			1
Ending balance at September 30, 2014	$	—		$	1		$	1
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	—		$	—		$	—
Power:
Beginning balance at January 1, 2014	$	19		$	(108	)	$	(89	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(23	)		(19	)		(42	)
Purchases		34			—			34
Settlements		(25	)		3			(22	)
Ending balance at September 30, 2014	$	5		$	(124	)	$	(119	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	(3	)	$	(21	)	$	(24	)
Uranium:
Beginning balance at January 1, 2014	$	(6	)	$	(a)		$	(6	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(1	)		(a)			(1	)
Settlements		4			(a)			4
Ending balance at September 30, 2014	$	(3	)	$	(a)		$	(3	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014	$	—		$	(a)		$	—


(a)	Not applicable.

Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level, but were recategorized to Level 3 because the inputs to the model became unobservable during the period or (2) existing assets and liabilities that were previously classified as Level 3, but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers between Level 1 and Level 3 for fuel oils were primarily caused by changes in availability of similar financial trades observable on electronic exchanges between the periods. Any reclassifications are reported as transfers out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the three and nine months ended September 30, 2015, and 2014, there were no transfers between Level 1, Level 2, and Level 3 related to derivative commodity contracts, with the exception of $2 million of transfers out of Level 3 into Level 1 related to fuel oil contracts at Ameren and Ameren Missouri for the nine months ended September 30, 2015.

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

The following table presents the carrying amounts and estimated fair values of our long-term debt, capital lease obligations and preferred stock at September 30, 2015, and December 31, 2014:



	September 30, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:^(a)
Long-term debt and capital lease obligations (including current portion)	$	6,376	$	6,916	$	6,240	$	7,135
Preferred stock	142		124		142		122
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion)	$	4,135	$	4,488	$	3,999	$	4,518
Preferred stock	80		75		80		73
Ameren Illinois:
Long-term debt	$	2,241	$	2,428	$	2,241	$	2,517
Preferred stock	62		49		62		49


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

NOTE 8 - RELATED PARTY TRANSACTIONS

Ameren (parent) and its subsidiaries have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of power purchases and sales, services received or rendered, and borrowings and lendings.

Transactions between affiliates are reported as intercompany transactions on their respective financial statements but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our material related party agreements, see Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K and the money pool arrangements discussed in Note 3 - Short-term Debt and Liquidity of this report.

Electric Power Supply Agreements

In April and September 2015, Ameren Illinois conducted procurement events, administered by the IPA, to purchase energy products through May 31, 2018. Ameren Missouri was among the winning suppliers in these events. As a result, in April 2015, Ameren Missouri and Ameren Illinois entered into energy product agreements by which Ameren Missouri agreed to sell and Ameren Illinois agreed to purchase 667,000 megawatthours at an average price of $36 per megawatthour during the period of June 1, 2015, through June 30, 2017. In September 2015, Ameren Missouri and Ameren Illinois entered into energy product agreements by which Ameren Missouri agreed to sell and Ameren Illinois agreed to purchase 339,000 megawatthours at an average price of $38 per megawatthour during the period of November 1, 2015 through May 31, 2018.

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, 2015 and 2014.



				Three Months				Nine Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2015	$	4	$	(a)	$	9	$	(a)
agreements with Ameren Illinois		2014		2		(a)		5		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2015		6		1		19		3
rent and facility services		2014		6		(b)		15		1
Ameren Missouri and Ameren Illinois	Operating Revenues	2015		1		(b)		2		(b)
miscellaneous support services		2014		(b)		(b)		1		(b)
Total Operating Revenues		2015	$	11	$	1	$	30	$	3
		2014		8		(b)		21		1
Ameren Illinois power supply	Purchased Power	2015	$	(a)	$	4	$	(a)	$	9
agreements with Ameren Missouri		2014		(a)		2		(a)		5
Ameren Illinois transmission	Purchased Power	2015		(a)		1		(a)		2
services with ATXI		2014		(a)		1		(a)		2
Total Purchased Power		2015	$	(a)	$	5	$	(a)	$	11
		2014		(a)		3		(a)		7
Ameren Services support services	Other Operations and Maintenance	2015	$	30	$	28	$	96	$	87
agreement		2014		25		26		90		80
Money pool borrowings (advances)	Interest Charges/ Miscellaneous Income	2015	$	(b)	$	(b)	$	(b)	$	(b)
		2014		(b)		(b)		(b)		(b)


(a)	Not applicable.


(b)	Amount less than $1 million.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

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

Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, Note 15 - Commitments and Contingencies, and Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions, Note 10 - Callaway Energy Center, and Note 12 - Divestiture Transactions and Discontinued Operations in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at September 30, 2015. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year. Both coverages were renewed in 2015.



Type and Source of Coverage	Maximum Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	375		$	—
Pool participation	12,986		^(a)	127		^(b)
	$	13,361	^(c)	$	127
Property damage:
NEIL	$	2,750	^(d)	$	27	^(e)
European Mutual Association for Nuclear Insurance	500		^(f)	—
	$	3,250		$	27
Replacement power:
NEIL	$	490	^(g)	$	10	^(e)


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


(b)	Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed United States commercial reactor, payable at $19 million per year.

(c)

Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $127 million per incident for each licensed reactor it operates with a maximum of $19 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.


(d)	NEIL provides $2.25 billion in property damage, decontamination, and premature decommissioning insurance for both radiation and nonradiation events. An additional $500 million is provided for radiation events only for a total of $2.75 billion.


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


(f)	European Mutual Association for Nuclear Insurance provides $500 million in excess of the $2.75 billion and $2.25 billion property coverage for radiation and nonradiation events, respectively, provided by NEIL.


(g)	Provides replacement power cost insurance in the event of a prolonged accidental outage. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first twelve weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Nonradiation events are sub-limited to $328 million.

The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The most recent five-year inflationary adjustment became effective in September 2013. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by the Price-Anderson Act.

Losses resulting from terrorist attacks on nuclear facilities are covered under NEIL’s policies, subject to an industrywide aggregate policy limit of $3.24 billion within a 12-month period, or $1.83 billion for events not involving radiation contamination.

If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by, insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of Ameren Missouri’s energy centers, Ameren Missouri has entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. Additionally, Ameren Missouri and Ameren Illinois have entered into various long-term commitments for purchased power and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

At September 30, 2015, total other obligations related to commitments for coal, natural gas, nuclear fuel, purchased power, methane gas, equipment, and meter reading services, among other agreements, at Ameren, Ameren Missouri, and Ameren Illinois were $4,832 million, $2,913 million, and $1,888 million, respectively.

In April and September 2015, Ameren Illinois conducted procurement events, administered by the IPA, to purchase energy products through May 31, 2018. In the April procurement event, Ameren Illinois contracted to purchase approximately 5,526,000 megawatthours of energy products for $185 million from June 1, 2015, through May 31, 2018. In the September procurement event, Ameren Illinois contracted to purchase approximately 2,592,000 megawatt hours of energy products for $83 million from November 1, 2015, through May 31, 2018. The results of both procurement events are included in Ameren’s and Ameren Illinois’ obligations discussed above. See Note 8 - Related Party Transactions in this report for additional information regarding energy product agreements between Ameren Missouri and Ameren Illinois as a result of these procurement events.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. From the beginning phases of siting and development to the operation of existing or new electric generation, transmission and distribution facilities and natural gas storage, transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, discharges to water, water usage, impacts to air, land, and water, and chemical and waste handling. Complex and lengthy processes are required to obtain and renew approvals, permits, or 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 is developing and implementing environmental regulations that will have a significant impact on the electric utility industry. Over time, compliance with these regulations could be costly for certain companies, including Ameren Missouri, that operate coal-fired power plants. Significant new rules proposed or promulgated include the regulation of CO₂ emissions from existing power plants through the Clean Power Plan and from new power plants through the revised NSPS; the CSAPR, which requires further reductions of SO₂ emissions and NO_x emissions

from power plants; a regulation governing management of CCR and CCR landfills and impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from power plants; revised NSPS for particulate matter, SO₂, and NO_x emissions from new sources; new effluent standards applicable to waste water discharges from power plants and new regulations under the Clean Water Act that could require significant capital expenditures, such as modifications to water intake structures or new cooling towers at Ameren Missouri’s energy centers. The EPA also periodically reviews and revises national ambient air quality standards, including those standards associated with emissions from power plants such as particulate matter, ozone, SO₂and NO_x. The EPA issued a more stringent national ambient air quality standard for ozone on October 1, 2015. Certain of these new regulations are likely to be challenged through litigation, so their ultimate implementation, as well as the timing of any such implementation, is uncertain. Although many details of future regulations are unknown, the combined effects of new environmental regulations could result in significant capital expenditures and increased operating costs for Ameren and Ameren Missouri. Compliance with all of these environmental laws and regulations could be prohibitively expensive, result in the closure or alteration of the operation of some of Ameren Missouri’s energy centers, or require capital investment. Ameren and Ameren Missouri expect these costs would be recoverable through rates, subject to MoPSC prudence review, but the nature and timing of costs, as well as the applicable regulatory framework, could result in regulatory lag.

Ameren Missouri's current plan for compliance with existing environmental regulations for air emissions includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. Ameren and Ameren Missouri estimate that they will need to make capital expenditures of $350 million to $400 million in the aggregate from 2015 through 2019 in order to comply with existing environmental regulations. Ameren Missouri may be required to install additional pollution controls within the next six to 10 years. This estimate includes our capital expenditures required for the CCR regulations that were published in 2015, compliance with the MATS, and the rule applicable to cooling water intake structures at existing power plants under the Clean Water Act, all of which are discussed below. This estimate does not include the impacts of the Clean Power Plan and the new effluent limitation guidelines applicable to steam electric generating units under the Clean Water Act, both of which are discussed below. Considerable uncertainty remains in this estimate. The actual amount of capital expenditures required to comply with existing environmental regulations may vary substantially from the above estimate due to uncertainty as to the precise compliance strategies that will be used and their ultimate cost, among other things.

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

Clean Air Act

Federal and state laws require significant reductions in SO₂and NO_x through either emission source reductions or the use and retirement of emission allowances. The CSAPR became effective on January 1, 2015, for SO₂ and annual NO_xreductions, and on May 1, 2015, for ozone season NO_x reductions. There will be further emission reduction requirements in 2017 and potentially more in subsequent years. Ameren Missouri expects to have sufficiently reduced emissions and have sufficient allowances to avoid purchasing allowances to comply with CSAPR for 2015. To achieve compliance with CSAPR, Ameren Missouri operates two scrubbers at its Sioux energy center and burns ultra-low sulfur coal. Ameren Missouri does not expect to make additional capital investments to comply with the current CSAPR requirements. However, Ameren Missouri expects to incur additional operations and maintenance costs to lower its emissions at one or more of its energy centers for compliance with the CSAPR in future years. These higher operations and maintenance costs are expected to be collected from customers through the FAC or higher base rates.

In December 2011, the EPA issued the MATS under the Clean Air Act, which requires reductions in emissions of mercury and other hazardous air pollutants, such as acid gases, trace metals, and hydrogen chloride. The MATS do not require a specific control technology to achieve the emission reductions. The MATS apply to each unit at a coal-fired power plant. However, in certain cases, compliance can be achieved by averaging emissions from similar units at the same power plant. Compliance was required by April 2015 or, with a case-by-case extension, by April 2016. Ameren Missouri's Labadie and Meramec energy centers were granted extensions. In June 2015, the United States Supreme Court remanded a case challenging the MATS to the United States Court of Appeals for the District of Columbia Circuit for further consideration and ruled that the EPA was required to consider costs before deciding whether regulation of emissions of mercury and other hazardous air pollutants from power plants was appropriate and necessary. Ameren Missouri expects to make additional capital investments at its Labadie and Meramec energy centers to comply with the MATS by April 2016. These capital expenditure investments are included in Ameren's and Ameren Missouri's estimate of capital expenditures to comply with existing environmental regulations discussed above. In addition, Ameren Missouri is incurring additional operations and maintenance costs to lower its emissions at its energy centers in compliance with the MATS. These higher operations and maintenance costs are being collected from customers through the FAC or higher base rates.

Greenhouse Gas Regulation

The finalized version of the Clean Power Plan, which sets forth CO₂emissions standards that will be applicable to existing power plants, was published in the Federal Register in October 2015 and will become effective in December 2015. The finalized regulations differ significantly from the proposed rule that the EPA issued in June 2014.

Under the Clean Power Plan, Ameren Missouri expects to incur increased net fuel and operating costs, and new or accelerated capital expenditures, in addition to making modifications to existing operations in order to achieve compliance. Missouri and Illinois are each required to reduce their greenhouse gas emissions significantly below 2005 levels by 2030. States are required to submit preliminary compliance plans to the EPA as early as 2016, although extensions until 2018 are available. The rule contains interim compliance periods commencing in 2022 that require each state to demonstrate progress in achieving its greenhouse gas reduction target. Ameren Missouri is evaluating the Clean Power Plan and its potential implementation by Missouri and Illinois. This assessment includes the potential impacts to its operations, including those related to electric system reliability and its level of investment in customer energy efficiency programs, renewable energy, and other forms of generation investment. Significant uncertainty exists regarding the impact of the Clean Power Plan, as the finalized rule is different from the proposed rule and its implementation will depend upon plans to be developed by the states. Numerous legal challenges are pending which could result in the rule being declared invalid or the nature and timing of CO₂ emissions reductions being revised. We cannot predict the outcome of the legal challenges or their impact on our results of operations, financial position or liquidity. Compliance measures could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and natural gas-fired energy centers, which could result in increased operating costs. Ameren Missouri expects substantially all of these increased costs to be recoverable, subject to MoPSC prudence review, through higher rates to customers, which could be significant.

Also, in August 2015, the EPA issued final regulations that set CO₂ emissions standards for new power plants. These new standards establish separate emissions limits for new natural gas-fired plants and new coal-fired plants.

Federal and state legislation or regulations that mandate limits on the emission of greenhouse gases may result in significant increases in capital expenditures and operating costs, which could lead to increased liquidity needs and higher financing costs. Mandatory limits on the emission of greenhouse gases could increase costs for Ameren Missouri’s customers or have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity if regulators delay or deny recovery in rates of these compliance costs. The cost of Ameren Illinois’ purchased power and gas purchased for resale could increase; however, Ameren Illinois expects these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. Ameren's and Ameren Missouri's earnings might benefit from increased investment to comply with greenhouse gas limitations to the extent that the investments are reflected and recovered timely in rates charged to customers.

NSR and Clean Air Litigation

In January 2011, the Department of Justice, on behalf of the EPA, filed a complaint against Ameren Missouri in the United

States District Court for the Eastern District of Missouri. The EPA's complaint, as amended in October 2013, alleges that in performing projects at its Rush Island coal-fired energy center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. Ameren Missouri anticipates a trial of this case will occur in 2016. Ameren Missouri believes its defenses are meritorious and is defending itself vigorously. However, there can be no assurances that it will be successful in its efforts.

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

Clean Water Act

In August 2014, the EPA published the 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. Implementation of this rule will be administered through each power plant’s water discharge permitting process. All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to this rule. The rule could have an adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers or extensive modifications to the cooling water systems at our energy centers and if those investments are not recovered timely in electric rates charged to its customers.

In September 2015, the EPA issued its final rule under the Clean Water Act to revise the effluent limitation guidelines applicable to steam electric generating units. Effluent limitation guidelines are national standards for wastewater discharges that are based on the effectiveness of available control technology. The EPA's rule prohibits effluent discharges of certain, but not all, waste streams and imposes more stringent limitations on certain components in wastewater discharges from power plants. All of Ameren Missouri’s coal-fired energy centers are subject to this rule. Each of Ameren Missouri’s energy centers will become subject to the revised limitations when it renews its wastewater discharge permit. These permits are scheduled to be renewed between 2018 and 2023. Ameren Missouri is evaluating the final rule, which will become effective in January 2016, and the possible effects on its operations.

Ash Management

The EPA issued regulations in 2015 regarding the management and disposal of CCR, which will affect future CCR disposal and handling costs at Ameren Missouri's energy centers. The regulations allow for the management of CCR as a solid waste, as well as for its continued beneficial uses, such as recycling, which could reduce the amount to be disposed. The

regulations also establish criteria regarding the structural integrity, location, and operation of CCR impoundments and landfills. They require groundwater monitoring and closure of impoundments if the groundwater standards are not achieved. During the second quarter of 2015, Ameren and Ameren Missouri recorded an increase to their AROs associated with CCR storage facilities as a result of the new regulations. See Note 1 - Summary of Significant Accounting Policies in this report for additional information. Ameren Missouri's capital expenditure plan includes the cost of constructing landfills as part of its environmental compliance plan, with expenditures beginning in 2015. Ameren Missouri expects certain of its ash ponds could be closed within the next five years.

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

Remediation

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

As of September 30, 2015, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois, which are in various stages of investigation, evaluation, remediation, and closure. Ameren Illinois estimates it could substantially conclude remediation efforts by 2025. The ICC allows Ameren Illinois to recover remediation and litigation costs associated with its former MGP sites from its electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently incurred. Costs are subject to annual review by the ICC. As of September 30, 2015, Ameren Illinois estimated the obligation related to these former MGP sites at $237 million to $309 million. Ameren and Ameren Illinois recorded a liability of $237 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate.

The scope and extent to which these former MGP sites are remediated may increase as remediation efforts continue. Considerable uncertainty remains in these estimates, as many factors can influence the ultimate actual costs, including site specific unanticipated underground structures, the degree to which groundwater is encountered, regulatory changes, local ordinances, and site accessibility. The actual costs may vary substantially from these estimates.

Ameren Illinois formerly used an off-site landfill, which Ameren Illinois did not own, in connection with the operation of a previously-owned energy center. Ameren Illinois could be required to perform certain maintenance activities at that landfill, which is now closed. As of September 30, 2015, Ameren Illinois estimated the obligation related to the landfill at $0.5 million to $6

million. Ameren Illinois recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. Ameren Illinois is also responsible for the cleanup of some underground storage tanks and a water treatment plant in Illinois. As of September 30, 2015, Ameren Illinois recorded a liability of $0.7 million to represent its best estimate of the obligation for these sites.

In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to a former coal tar distillery in St. Louis, Missouri operated by Koppers Company or its predecessor and successor companies. While Ameren Missouri is the current owner of the site, it did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other potentially responsible parties, have completed site investigation activities and have submitted their findings to the EPA. As of September 30, 2015, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren Missouri recorded a liability of $2 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

Ameren Missouri also participated in the investigation of various sites located in Sauget, Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies, including Solutia, Inc., that former landfills and lagoons at those sites may contain soil and groundwater contamination. These sites are known as Sauget Area 2. 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 as a landfill.

In December 2013, the EPA issued its record of decision for Sauget Area 2 approving the investigation and the remediation alternatives recommended by the potentially responsible parties. Further negotiation among the potentially responsible parties will determine how to fund the implementation of the EPA-approved cleanup remedies. As of September 30, 2015, Ameren Missouri estimated its obligation related to Sauget Area 2 at $1 million to $2.5 million. Ameren Missouri recorded a liability of $1 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate.

In December 2012, Ameren Missouri signed an administrative order with the EPA and agreed to investigate soil and groundwater conditions at an Ameren Missouri-owned substation in St. Charles, Missouri. As of September 30, 2015, Ameren Missouri estimated and recorded a $0.8 million liability related to the remaining cleanup of the site.

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.

Pumped-storage Hydroelectric Facility Breach

In December 2005, there was a breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. The breach resulted in significant flooding in the local area, which damaged a state park. Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles.

In 2010, Ameren Missouri sued an insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the litigation, which is pending in the United States District Court for the Southern District of New York, Ameren Missouri claims that the insurance company breached its duty to indemnify Ameren Missouri for losses resulting from the incident.

As of September 30, 2015, Ameren Missouri had a net insurance receivable balance of $41 million. The insurance claim was $54 million as of September 30, 2015. Ameren Missouri expects to collect this receivable from the insurance company in the pending litigation described above. This receivable is included in “Other assets” on Ameren’s and Ameren Missouri’s balance sheets as of September 30, 2015. Ameren's and Ameren Missouri's results of operations, financial position, and liquidity could be adversely affected if Ameren Missouri's insurance receivable balance is not collected.

Asbestos-related Litigation

Ameren, Ameren Missouri, and Ameren Illinois have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure at our current and former energy centers. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies, with 73 as the average number of parties as of September 30, 2015. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.

The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of September 30, 2015:


(a)	Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.

As of September 30, 2015, Ameren, Ameren Missouri, and Ameren Illinois had “Other current liabilities” of $8 million, $3 million, and $5 million, respectively, recorded to represent their best estimate of their obligations related to asbestos claims.

Ameren Illinois has a tariff rider to recover the costs of IP asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are to be recovered from a trust fund that was

established when Ameren acquired IP. At September 30, 2015, the trust fund balance was $22 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the trust fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. The rider will permit recovery from customers within IP’s historical service territory.

NOTE 10 - CALLAWAY ENERGY CENTER

Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. Under the NWPA, Ameren and other utilities that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established the fee that these utilities pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatthour generated and sold by those plants. The NWPA also requires the DOE annually to review the nuclear waste fee 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, 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 is currently suspended.

Although both the NWPA and the standard contract stated that the DOE would begin to dispose of spent nuclear fuel by 1998, the DOE is not meeting its disposal obligation. The DOE's delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway energy center is not expected to adversely affect the continued operations of the energy center. Ameren Missouri has sufficient installed capacity at the Callaway energy center to store its spent nuclear fuel generated through the end of the energy center’s operating license in 2044.

As a result of the DOE's failure to begin to dispose of spent nuclear fuel from commercial nuclear energy centers and fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners sued the DOE to recover costs, such as certain NRC fees and Missouri ad valorem taxes incurred for

ongoing storage of their spent fuel. The lawsuit resulted in a settlement agreement that provides for annual recovery of additional spent fuel storage and related costs incurred from 2010 through 2016, with the ability to extend the recovery period as mutually agreed upon by the parties. Included in these reimbursements are costs related to the dry spent fuel storage facility at the Callaway energy center, to which Ameren Missouri began transferring spent fuel assemblies in 2015. Ameren Missouri will continue to apply for reimbursement from the DOE for allowable costs associated with the dry spent fuel storage facility.

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. Following the NRC’s decision in March 2015 to extend the Callaway energy center’s operating license from 2024 to 2044, an updated cost study and a revised funding analysis were filed with the MoPSC in April 2015. Ameren Missouri’s April 2015 filing supported no change in electric service rates. There is no time requirement by which the MoPSC must issue an order regarding the decommissioning cost included in Ameren Missouri’s electric service rates. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the trust fund for Ameren Missouri's Callaway energy center is reported as "Nuclear decommissioning trust fund" in Ameren's and Ameren Missouri's balance sheets. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory liability.

NOTE 11 - RETIREMENT BENEFITS

Ameren’s pension plans are funded in compliance with income tax regulations and to meet federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at September 30, 2015, the plan’s estimated investment performance through September 30, 2015, and Ameren’s pension funding policy, Ameren expects to make annual contributions of $50 million to $110 million through 2019, with aggregate estimated contributions of $350 million. These amounts are estimates which may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Separately, our policy for postretirement benefits is primarily to fund the voluntary employees’ beneficiary association trusts to match the annual postretirement expense.

The following table presents the components of the net periodic benefit cost (benefit) incurred for Ameren’s pension and postretirement benefit plans for the three and nine months ended September 30, 2015 and 2014:



	Pension Benefits												Postretirement Benefits
	Three Months						Nine Months						Three Months						Nine Months
	2015			2014			2015			2014			2015			2014			2015			2014
Service cost	$	23		$	20		$	69		$	60		$	6		$	5		$	17		$	14
Interest cost	43			46			130			137			12			12			36			37
Expected return on plan assets	(62		)	(58		)	(186		)	(172		)	(17		)	(16		)	(51		)	(48		)
Amortization of:
Prior service benefit	—			(1		)	—			(1		)	(1		)	(2		)	(3		)	(4		)
Actuarial loss (gain)	19			13			56			37			1			(2		)	4			(5		)
Settlement loss	—			—			1			—			—			—			—			—
Net periodic benefit cost (benefit)	$	23		$	20		$	70		$	61		$	1		$	(3	)	$	3		$	(6	)

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, 2015 and 2014:



	Pension Benefits								Postretirement Benefits
	Three Months				Nine Months				Three Months						Nine Months
	2015		2014		2015		2014		2015			2014			2015			2014
Ameren Missouri^(a)	$	14	$	13	$	42	$	38	$	2		$	—		$	6		$	2
Ameren Illinois	9		7		28		22		—			(3		)	(2		)	(7		)
Other	—		—		—		1		(1		)	—			(1		)	(1		)
Ameren^(a)(b)	$	23	$	20	$	70	$	61	$	1		$	(3	)	$	3		$	(6	)


(a)	The amounts above do 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 built into rates.


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

NOTE 12 - DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS

On December 2, 2013, Ameren completed the divestiture of New AER to IPH in accordance with the transaction agreement between Ameren and IPH dated March 14, 2013, as amended by a letter agreement dated December 2, 2013. The transaction agreement with IPH, as amended, provided that if the Elgin, Gibson City, and Grand Tower gas-fired energy centers were subsequently sold by Medina Valley and if Medina Valley received additional proceeds from such sale, Medina Valley would pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the $137.5 million previously paid to Genco.

On January 31, 2014, Medina Valley completed the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital for a total purchase price of $168 million. The agreement with Rockland Capital requires a portion of the purchase price to be held in escrow until January 31, 2016, to fund certain indemnity obligations, if any, of Medina Valley. The Rockland Capital escrow receivable balance and the corresponding payable due to Genco, both totaling $14 million, are reflected on Ameren's September 30, 2015 consolidated balance sheet in "Other current assets" and in "Other current liabilities," respectively. Medina Valley expects to pay Genco any amount it receives from the escrow on January 31, 2016. Ameren did not record a gain from its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers.

Discontinued Operations Presentation

See Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information related to disposal groups. All matters related to the final tax basis of New AER and the related tax benefit resulting from the divested merchant generation business have been resolved with the completion of the IRS’ audit for 2013. During the second quarter of 2015, based on the completion of the IRS audit, Ameren removed a reserve for unrecognized tax benefits recorded in 2013 and recognized a tax benefit from discontinued operations. See Note 1 - Summary of Significant Accounting Policies for additional information regarding the Ameren Companies’ uncertain tax positions.

The following table presents the components of discontinued operations in Ameren's consolidated statement of income for the three and nine months ended September 30, 2015 and 2014:



	Three Months						Nine Months
	2015			2014			2015		2014
Operating revenues	$	—		$	—		$	—	$	1
Operating benefits (expenses)	(1		)	(1		)	2		(4		)
Operating income (loss) before income tax	(1		)	(1		)	2		(3		)
Income tax benefit	1			—			50		—
Income (loss) from discontinued operations, net of taxes	$	—		$	(1	)	$	52	$	(3	)

The following table presents the carrying amounts of the components of assets and liabilities of Ameren’s discontinued operations, which consist primarily of AROs and related deferred income tax assets associated with the abandoned Meredosia and Hutsonville energy centers, at September 30, 2015, and December 31, 2014:



	September 30, 2015		December 31, 2014
Assets of discontinued operations
Accumulated deferred income taxes, net	$	17	$	15
Total assets of discontinued operations	$	17	$	15
Liabilities of discontinued operations
Accounts payable and other current obligations	$	1	$	1
Asset retirement obligations	29		32
Total liabilities of discontinued operations	$	30	$	33

Pursuant to the IPH transaction agreement, as amended, Ameren is obligated to pay up to $25 million for certain liabilities, which were included in "Other current liabilities" on Ameren's September 30, 2015 consolidated balance sheet as the payment is expected to be made by the end of 2015.

Included in “Miscellaneous accounts and notes receivable” on Ameren’s consolidated balance sheet is a note receivable from Marketing Company related to the cash collateral support provided to New AER. The note receivable balance was $8 million and $12 million at September 30, 2015, and December 31, 2014, respectively. This note receivable is due to Ameren, with interest, on December 2, 2015, or sooner as cash collateral requirements are reduced. In addition, as of September 30, 2015, if Ameren’s credit ratings had been below investment grade, Ameren could have been required to post additional cash collateral in support of New AER in the amount of $21 million, which includes $6 million currently covered by Ameren guarantees discussed below. This cash collateral support is part of Ameren’s obligation to provide certain limited credit support to New AER until December 2, 2015, as discussed below.

Ameren Guarantees and Letters of Credit

The IPH transaction agreement, as amended, requires Ameren to maintain its financial obligations with respect to all

credit support provided to New AER as of the December 2, 2013 closing date of the divestiture. Ameren must also provide such additional credit support as required by contracts entered into prior to the closing date, in each case until December 2, 2015. IPH shall indemnify Ameren for any payments Ameren makes pursuant to these credit support obligations if the counterparty does not return the posted collateral to Ameren. IPH's indemnification obligation is secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren pursuant to which Dynegy will, among other things, guarantee IPH's indemnification obligations until December 2, 2015.

In addition to the $25 million of liabilities recorded on Ameren’s September 30, 2015 consolidated balance sheet, Ameren had a total of $74 million in guarantees outstanding for New AER that were not recorded on Ameren’s September 30, 2015 consolidated balance sheet. Almost all of these guarantees support Marketing Company for physically and financially settled power transactions with its counterparties that were in place at the December 2, 2013 closing of the divestiture, as well as for Marketing Company's clearing broker and other service agreements. If Marketing Company did not fulfill its obligations to these counterparties who had active open positions as of September 30, 2015, Ameren would have been required under its

guarantees to provide $6 million to the counterparties. Also, at September 30, 2015, Ameren had issued letters of credit totaling $9 million as credit support on behalf of New AER. Ameren has not recorded a liability for these contingent obligations because it

does not believe a payment with respect to any of these guarantees or letters of credit was probable as of September 30, 2015.

NOTE 13 - SEGMENT INFORMATION

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

The following table presents information about the reported revenues and net income attributable to Ameren common stockholders from continuing operations for the three and nine months ended September 30, 2015 and 2014, and total assets of continuing operations as of September 30, 2015, and December 31, 2014:



Three Months	Ameren Missouri		Ameren Illinois		Other			Intersegment Eliminations			Ameren
2015
External revenues	$	1,160	$	654	$	19		$	—		$	1,833
Intersegment revenues	11		1		1			(13		)	—
Net income attributable to Ameren common stockholders from continuing operations	239		98		6			—			343
2014
External revenues	$	1,089	$	572	$	9		$	—		$	1,670
Intersegment revenues	8		—		2			(10		)	—
Net income (loss) attributable to Ameren common stockholders from continuing operations	222		75		(3		)	—			294
Nine Months
2015
External revenues	$	2,825	$	1,910	$	55		$	—		$	4,790
Intersegment revenues	30		3		2			(35		)	—
Net income attributable to Ameren common stockholders from continuing operations	341		182		26			—			549
2014
External revenues	$	2,793	$	1,864	$	26		$	—		$	4,683
Intersegment revenues	21		1		3			(25		)	—
Net income (loss) attributable to Ameren common stockholders from continuing operations	395		156		(10		)	—			541
As of September 30, 2015:
Total assets	$	13,941	$	8,656	$	1,358		$	(513	)	$	23,442	^(a)
As of December 31, 2014:
Total assets	$	13,541	$	8,381	$	942		$	(203	)	$	22,661	^(a)

(a) Excludes total assets from discontinued operations of $17 million and $15 million as of September 30, 2015 and December 31, 2014, respectively.

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

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


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


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

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

The operating results, assets, and liabilities of the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers have been presented separately as discontinued operations for all periods presented in this report. Unless otherwise stated, the following sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations exclude discontinued operations for all periods presented. See Note 12 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for additional information regarding the discontinued operations presentation. See Note 16 - Divestiture Transactions and

Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information regarding the divestiture transactions.

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

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

OVERVIEW

Net income attributable to Ameren common stockholders from continuing operations was $343 million in the third quarter of 2015, compared with $294 million in the third quarter of 2014. Net income attributable to Ameren common stockholders from continuing operations was $549 million in the first nine months of 2015, compared with $541 million in the first nine months of 2014.

Net income from continuing operations at Ameren was favorably affected in the third quarter and the first nine months of 2015, compared with the year-ago periods, by increased Ameren Illinois and ATXI electric transmission service and Ameren Illinois electric delivery service earnings, reflecting Ameren’s strategy to allocate incremental capital to those businesses, as well as a lower effective income tax rate. Increased electric sales volumes, primarily due to warmer summer temperatures, also contributed to the increase in earnings. Additionally, Ameren Illinois electric delivery service earnings increased due to the timing of earnings under formula ratemaking and, in the third quarter of 2015, seasonal rate redesign. The increase in Ameren’s net income from continuing operations for the first nine months of 2015 was partially offset by a provision recognized as a result of Ameren Missouri’s discontinued efforts to license and build a second nuclear unit at its existing Callaway energy center site and a reduction in the recognized return on equity related to businesses that operate under formula rates.

Ameren remains focused on executing its strategy of investing in and operating its utilities in a manner consistent with existing regulatory frameworks, enhancing those frameworks and advocating for responsible energy policies, as well as creating and capitalizing on opportunities for investment for the benefit of its customers and shareholders. Ameren continues to allocate significant amounts of capital to those businesses that are supported by modern, constructive regulatory frameworks. Ameren invested $886 million of its $1.3 billion in capital expenditures during the first nine months of 2015 in FERC-

regulated electric transmission projects and Ameren Illinois electric and natural gas delivery service infrastructure.

Construction continues on ATXI’s $1.4 billion Illinois Rivers transmission project. In September 2015, the ICC granted a certificate of public convenience and necessity and project approval for the approximately $150 million Spoon River project. Line construction on this project is expected to begin in late 2016. In June 2015, ATXI made a filing with the MoPSC requesting a certificate of convenience and necessity for the approximately $225 million Mark Twain transmission project. A decision is expected from the MoPSC in 2016. Regarding the complaint cases filed with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff, a proposed order in the first complaint case from the FERC’s administrative law judge is required to be issued no later than November 30, 2015, which will subsequently require FERC approval. Final FERC orders are not expected until 2016 in the first complaint case and 2017 in the second complaint case.

Ameren Illinois has invested approximately $410 million in electric and natural gas delivery infrastructure projects in the first nine months of 2015, including those that are part of its modernization action plan. It remains on track to meet its investment, reliability, advanced metering, and job creation goals under the IEIMA. Additionally, Ameren Illinois has been focused on achieving positive resolutions of its pending electric delivery service formula rate update proceeding and natural gas delivery service rate case. ICC decisions in both cases are required by December 2015.

Consistent with its strategic plan, one of Ameren’s goals is to earn at or close to the allowed return on common equity in each of its jurisdictions. This objective is more challenging in Missouri given the use of a historical test year and a lengthy regulatory approval process, among other things. Ameren Missouri attempts to mitigate this regulatory lag through continuous improvement efforts and by pursuing cost reductions through its operating and support organization as well as by seeking rate adjustments. Additionally, it continues its advocacy efforts with Missouri’s policymakers and key stakeholders to modernize the state’s regulatory framework. Since 2013, Ameren Missouri has been executing on a comprehensive three-year energy efficiency plan under the MEEIA, which has been more successful than anticipated resulting in substantial benefits to Ameren Missouri’s customers. Seeking to extend these energy efficiency programs, Ameren Missouri filed a proposed MEEIA plan for 2016 through 2018, which the MoPSC rejected in October 2015. Ameren Missouri is studying the MoPSC’s October 2015 order and evaluating whether to file another proposed energy efficiency plan with the MoPSC.

Ameren estimates its capital expenditures from 2015 through 2019 will be $8.6 billion to $9.3 billion, with $2.0 billion expected in 2015. Ameren is currently evaluating potential capital expenditures at Ameren Illinois of an estimated $500 million to $1 billion that are incremental to the estimates above. Ameren will continue to evaluate these investment opportunities as a part of its normal annual planning process. These incremental

investments would primarily be for the replacement of aging electric and natural gas delivery infrastructure to sustain and improve reliability for customers and would occur after 2016.

The impact of the Clean Power Plan on Ameren’s operations, infrastructure investment plans, and customers’ rates in Missouri and Illinois will be driven by those states’ implementation plans, which may not be finalized until 2018. Ameren Missouri expects its compliance plan for the Clean Power Plan will provide incremental investment opportunities, including those for renewable energy and natural gas-fired generation.

Reflecting confidence in Ameren’s long-term strategy and outlook, Ameren’s board of directors increased the quarterly common stock dividend to 42.5 cents per share in October 2015, resulting in an annualized equivalent dividend rate of $1.70 per share.

RESULTS OF OPERATIONS

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

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

Ameren Illinois' electric delivery service utility business, pursuant to the IEIMA, conducts an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement included in customer rates for that year, with recoveries from, or refunds to, customers made in a subsequent year. Included in Ameren Illinois' revenue requirement reconciliation is a formula for the return on equity, which is equal to the average of the monthly yields of 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois' annual return on equity is

directly correlated to yields on United States Treasury bonds. Ameren Illinois and ATXI use a company-specific, forward-looking rate formula framework in setting their transmission rates. These forward-looking rates are updated each January with forecasted information. A reconciliation during the year, which adjusts for the actual revenue requirement and actual sales volumes, is used to adjust billing rates in a subsequent year.

Ameren Illinois’ and ATXI’s electric transmission service businesses and Ameren Illinois’ electric delivery service business operate under formula ratemaking, designed to provide for the recovery of actual costs of service that are prudently incurred as well as a return on equity. While rate-regulated, Ameren Illinois’

natural gas business and Ameren Missouri do not operate under formula ratemaking. Additionally, Ameren (parent) does not operate under formula ratemaking.

We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of Ameren Missouri's energy centers and our transmission and distribution systems and the level of purchased power costs, operations and maintenance costs, and capital investment are key factors that we seek to manage in order to optimize our results of operations, financial position, and liquidity.

Earnings Summary

The following table presents a summary of Ameren's earnings for the three and nine months ended September 30, 2015 and 2014:



	Three Months				Nine Months
	2015		2014		2015		2014
Net income attributable to Ameren common stockholders	$	343	$	293	$	601	$	538
Earnings per common share - diluted	1.41		1.20		2.47		2.20
Net income attributable to Ameren common stockholders - continuing operations	$	343	$	294	$	549	$	541
Earnings per common share - diluted - continuing operations	1.41		1.20		2.26		2.21

Net income attributable to Ameren common stockholders from continuing operations increased $49 million, or 21 cents per diluted share, in the third quarter of 2015 compared with the same period in 2014. The increase between periods was due to a $17 million increase in net income from the Ameren Missouri segment and a $23 million increase in net income from the Ameren Illinois segment. Additionally, Ameren (parent) and nonregistrant subsidiaries had net income of $6 million in the third quarter of 2015 compared with a $3 million loss in the same period in 2014, which included net income from ATXI of $9 million and $5 million, respectively.

Net income attributable to Ameren common stockholders from continuing operations increased $8 million, or 5 cents per diluted share, in the first nine months of 2015 compared with the same period in 2014. The increase between periods was due, in part, to net income from Ameren (parent) and nonregistrant subsidiaries of $26 million in the first nine months of 2015 compared with a $10 million net loss in the same period in 2014, which included net income from ATXI of $26 million and $13 million, respectively. Additionally, net income from the Ameren Illinois segment increased $26 million compared to 2014. Partially offsetting the increase was a $54 million decrease in net income from the Ameren Missouri segment compared to 2014.

Net income attributable to Ameren common stockholders from discontinued operations was $- million and $52 million, in the third quarter and the first nine months of 2015, respectively, compared with a net loss of $1 million and $3 million, respectively, in the year-ago periods. During the second quarter of 2015, based on the completion of the IRS audit of Ameren’s 2013 tax year, Ameren removed a reserve for unrecognized tax benefits of $53 million recorded in 2013, related to the divestiture

of New AER, and recognized a tax benefit from discontinued operations.

Earnings per share from continuing operations were favorably affected in the third quarter and the first nine months of 2015, respectively, compared with the year-ago periods (except where a specific period is referenced), by:

•

increased Ameren Illinois and ATXI electric transmission service and Ameren Illinois electric delivery service earnings under formula ratemaking primarily due to additional rate base investment as well as interest earned on revenue requirement reconciliation adjustment regulatory assets (5 cent per share and 15 cents per share, respectively). These earnings were reduced by the recognition of a liability for a potential refund to customers based on the pending FERC complaint cases regarding the allowed base return on common equity as well as a lower return on equity related to Ameren Illinois electric delivery service investments due to a reduction in the 30-year United States Treasury bond yields (3 cents per share and 7 cents per share, respectively);


•	a decrease in the effective tax rate primarily due to a decrease in Ameren (parent)’s tax expense related to stock-based compensation and a reduced Illinois state statutory tax rate for Ameren Illinois’ natural gas business (2 cents per share and 6 cents per share, respectively);


•	increased Ameren Illinois earnings resulting from a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism (4 cents per share for the nine months ended September 30, 2015);


•	increased electric demand primarily due to warmer summer temperatures in 2015, which, in the first nine months of 2015, was partially offset by decreased weather-related

natural gas demand (estimated at 9 cents per share and 3 cents per share, respectively);

•

decreased other operations and maintenance expenses for those businesses not operating under formula rates, excluding increases related to Ameren Missouri’s April 2015 MoPSC electric rate order (3 cents per share for the nine months ended September 30, 2015). Other operations and maintenance expenses decreased due to a reduction in Ameren Missouri low-level radioactive nuclear waste disposal costs and in its bad debt expense, decreased Ameren Illinois natural gas maintenance expenditures, and lower costs at nonregistrant subsidiaries;


•	decreased interest expense at Ameren (parent) primarily due to higher-cost debt being replaced with lower-cost debt (3 cents per share for the nine months ended September 30, 2015);


•	increased Ameren Illinois electric delivery service earnings due to timing of earnings under formula ratemaking and, in the third quarter of 2015, seasonal rate redesign (6 cents per share and 2 cents per share, respectively); and


•	increased net shared benefits realized under the MEEIA at Ameren Missouri (1 cent per share and 2 cents per share, respectively).

Earnings per share from continuing operations were unfavorably affected in the third quarter and the first nine months of 2015, respectively, compared with the year-ago periods (except where a specific period is referenced), by:


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


•	increased net financing costs at Ameren Missouri, primarily due to a reduction in allowance for funds used during construction as multiple significant electric capital projects were completed in 2014 (2 cents per share and 5 cents per share, respectively);


•	increased depreciation and amortization expenses for those businesses not operating under formula rates, primarily resulting from electric capital additions at Ameren Missouri, which were not reflected in customer rates until May 30, 2015, and amortization of natural gas software at Ameren Illinois (1 cent per share and 4 cents per share, respectively); and

•

Excluding the estimated effects of weather, earnings were unfavorably affected by a decrease in electric demand at Ameren Missouri, primarily as a result of non-MEEIA related customer energy efficiency measures and a reduction in Noranda sales volumes, partially offset by an increase in residential and commercial sales volumes at Ameren Illinois (estimated at 4 cents per share for nine months ended September 30, 2015).

The cents per share information presented in the explanations above is based on the diluted average shares outstanding in the third quarter and first nine months of 2014. For additional details regarding the Ameren Companies’ results of operations, including explanations of Margins, Other Operations and Maintenance Expenses, Provision for Callaway Construction and Operating License, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income and Expenses, Interest Charges, Income Taxes and Income (Loss) from Discontinued Operations, Net of Taxes, see the major headings below.

Below is a table of income statement components by segment for the three and nine months ended September 30, 2015 and 2014:



	Ameren Missouri			Ameren Illinois			Other / Intersegment Eliminations			Ameren
Three Months 2015:
Electric margins	$	863		$	412		$	13		$	1,288
Natural gas margins	14			82			(1		)	95
Other revenues	1			—			(1		)	—
Other operations and maintenance	(233		)	(202		)	7			(428		)
Depreciation and amortization	(125		)	(74		)	(2		)	(201		)
Taxes other than income taxes	(97		)	(29		)	(2		)	(128		)
Other income (expense)	11			1			2			14
Interest charges	(54		)	(33		)	—			(87		)
Income taxes	(140		)	(59		)	(9		)	(208		)
Income from continuing operations	240			98			7			345
Loss from discontinued operations, net of tax	—			—			—			—
Net income	240			98			7			345
Noncontrolling interests - preferred dividends	(1		)	—			(1		)	(2		)
Net income attributable to Ameren common stockholders	$	239		$	98		$	6		$	343
Three Months 2014:
Electric margins	$	813		$	356		$	4		$	1,173
Natural gas margins	14			84			—			98
Other operations and maintenance	(226		)	(185		)	9			(402		)
Depreciation and amortization	(118		)	(66		)	(3		)	(187		)
Taxes other than income taxes	(89		)	(31		)	(1		)	(121		)
Other income (expense)	11			2			1			14
Interest charges	(53		)	(31		)	(1		)	(85		)
Income taxes	(129		)	(54		)	(11		)	(194		)
Income (loss) from continuing operations	223			75			(2		)	296
Loss from discontinued operations, net of tax	—			—			(1		)	(1		)
Net income (loss)	223			75			(3		)	295
Noncontrolling interests - preferred dividends	(1		)	—			(1		)	(2		)
Net income (loss) attributable to Ameren common stockholders	$	222		$	75		$	(4	)	$	293
Nine Months 2015:
Electric margins	$	1,995		$	999		$	36		$	3,030
Natural gas margins	58			320			(1		)	377
Other revenues	2			—			(2		)	—
Other operations and maintenance	(673		)	(606		)	23			(1,256		)
Provision for Callaway construction and operating license	(69		)	—			—			(69		)
Depreciation and amortization	(367		)	(220		)	(7		)	(594		)
Taxes other than income taxes	(262		)	(101		)	(6		)	(369		)
Other income (expense)	29			5			(2		)	32
Interest charges	(164		)	(99		)	(1		)	(264		)
Income taxes	(205		)	(114		)	(14		)	(333		)
Income from continuing operations	344			184			26			554
Income from discontinued operations, net of tax	—			—			52			52
Net income	344			184			78			606
Noncontrolling interests - preferred dividends	(3		)	(2		)	—			(5		)
Net income attributable to Ameren common stockholders	$	341		$	182		$	78		$	601
Nine Months 2014:
Electric margins	$	1,967		$	906		$	13		$	2,886
Natural gas margins	59			329			(1		)	387
Other revenues	1			—			(1		)	—
Other operations and maintenance	(672		)	(580		)	21			(1,231		)
Depreciation and amortization	(351		)	(193		)	(7		)	(551		)
Taxes other than income taxes	(248		)	(109		)	(5		)	(362		)
Other income (expense)	35			5			—			40
Interest charges	(159		)	(90		)	(17		)	(266		)
Income taxes	(234		)	(110		)	(13		)	(357		)
Income (loss) from continuing operations	398			158			(10		)	546
Loss from discontinued operations, net of tax	—			—			(3		)	(3		)
Net income (loss)	398			158			(13		)	543
Noncontrolling interests - preferred dividends	(3		)	(2		)	—			(5		)
Net income (loss) attributable to Ameren common stockholders	$	395		$	156		$	(13	)	$	538

Margins

The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in the three and nine months ended September 30, 2015, compared with the year-ago periods. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as gas revenues less gas purchased for resale. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP and may not be comparable to other companies' presentations or more useful than the GAAP information we provide elsewhere in this report.



Three Months	Ameren Missouri			Ameren Illinois			Other^(a)			Ameren
Electric revenue change:
Effect of weather (estimate)^(b)	$	34		$	8		$	—		$	42
Base rates (estimate)	42			20			—			62
Sales volume (excluding the estimated effect of weather)	(10		)	6			—			(4		)
Off-system sales and transmission services revenues	(1		)	—			—			(1		)
MEEIA (energy efficiency) recovery mechanisms	8			—			—			8
Transmission services revenues^(c)	1			2			9			12
Bad debt, energy efficiency programs, and environmental remediation cost riders	—			4			—			4
Gross receipts tax	5			—			—			5
Illinois seasonal rate redesign	—			11			—			11
Other	—			5			(2		)	3
Cost recovery mechanisms - offsets in fuel and purchased power:
Pass-through power supply costs	—			35			—			35
Transmission services recovery mechanism	—			4			—			4
Recovery of FAC under-recovery	(4		)	—			—			(4		)
Total electric revenue change	$	75		$	95		$	7		$	177
Fuel and purchased power change:
Energy costs	$	9		$	—		$	—		$	9
Effect of weather (estimate)^(b)	(6		)	—			—			(6		)
Effect of higher net energy costs included in base rates	(30		)	—			—			(30		)
FAC exclusion of transmission services expenses^(c)	(4		)	—			—			(4		)
Other	2			—			2			4
Cost recovery mechanisms - offsets in electric revenue:
Pass-through power supply costs	—			(35		)	—			(35		)
Transmission services recovery mechanism	—			(4		)	—			(4		)
Recovery of FAC under-recovery	4			—			—			4
Total fuel and purchased power change	$	(25	)	$	(39	)	$	2		$	(62	)
Net change in electric margins	$	50		$	56		$	9		$	115
Natural gas revenue change:
Effect of weather (estimate)^(b)	$	(1	)	$	(2	)	$	—		$	(3	)
Bad debt, energy efficiency programs, and environmental remediation cost riders	—			(1		)	—			(1		)
Pass-through purchased gas costs - offset in gas purchased for resale	(1		)	(8		)	—			(9		)
Other	—			(1		)	—			(1		)
Total natural gas revenue change	$	(2	)	$	(12	)	$	—		$	(14	)
Gas purchased for resale change:
Effect of weather (estimate)^(b)	$	1		$	2		$	—		$	3
Pass-through purchased gas costs - offset in natural gas revenue	1			8			(1		)	8
Total gas purchased for resale change	$	2		$	10		$	(1	)	$	11
Net change in natural gas margins	$	—		$	(2	)	$	(1	)	$	(3	)



Nine Months	Ameren Missouri			Ameren Illinois			Other^(a)			Ameren
Electric revenue change:
Effect of weather (estimate)^(b)	$	10		$	1		$	—		$	11
Base rates (estimate)	57			35			—			92
Sales volume (excluding the estimated effect of weather)	(28		)	2			—			(26		)
Off-system sales and transmission services revenues	(3		)	—			—			(3		)
MEEIA (energy efficiency) recovery mechanisms	10			—			—			10
Transmission services revenues^(c)	1			15			27			43
Bad debt, energy efficiency programs, and environmental remediation cost riders	—			10			—			10
Gross receipts tax	7			—			—			7
Purchased power rider order	—			15			—			15
Other	2			7			(8		)	1
Cost recovery mechanisms - offsets in fuel and purchased power:
Pass-through power supply costs	—			60			—			60
Transmission services recovery mechanism	—			9			—			9
Total electric revenue change	$	56		$	154		$	19		$	229
Fuel and purchased power change:
Energy costs	$	19		$	—		$	—		$	19
Effect of weather (estimate)^(b)	1			4			—			5
Effect of higher net energy costs included in base rates	(41		)	—			—			(41		)
FAC exclusion of transmission services expenses^(c)	(5		)	—			—			(5		)
Other	(2		)	4			4			6
Cost recovery mechanisms - offsets in electric revenue:
Pass-through power supply costs	—			(60		)	—			(60		)
Transmission services recovery mechanism	—			(9		)	—			(9		)
Total fuel and purchased power change	$	(28	)	$	(61	)	$	4		$	(85	)
Net change in electric margins	$	28		$	93		$	23		$	144
Natural gas margins change:
Effect of weather (estimate)^(b)	$	(11	)	$	(29	)	$	—		$	(40	)
Bad debt, energy efficiency programs, and environmental remediation cost riders	—			(3		)	—			(3		)
Gross receipts tax	—			(4		)	—			(4		)
Pass-through purchased gas costs - offset in gas purchased for resale	(5		)	(71		)	—			(76		)
Other	—			1			—			1
Total natural gas revenue change	$	(16	)	$	(106	)	$	—		$	(122	)
Gas purchased for resale change:
Effect of weather (estimate)^(b)	$	10		$	26		$	—		$	36
Pass-through purchased gas costs - offset in natural gas revenue	5			71			—			76
Total gas purchased for resale change	$	15		$	97		$	—		$	112
Net change in natural gas margins	$	(1	)	$	(9	)	$	—		$	(10	)


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


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


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

Ameren Corporation

Ameren's electric margins increased $115 million, or 10%, and $144 million, or 5%, for the three and nine months ended September 30, 2015, respectively, compared with the year-ago periods. Ameren's natural gas margins decreased $3 million, or 3%, and $10 million, or 3%, for the three and nine months ended September 30, 2015, respectively, compared with the year-ago periods. Ameren’s results were primarily driven by the Ameren Missouri and Ameren Illinois results, as discussed below. Ameren's electric margins also reflected ATXI’s results of operations. ATXI’s transmission services revenues increased $9

million and $27 million for the three and nine months ended September 30, 2015, respectively, compared with the year-ago periods. The increases were due to higher rate base investment and recoverable costs under forward-looking formula ratemaking, but were reduced by the recognition of a potential refund to customers based on the pending FERC complaint cases regarding the allowed base return on common equity. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding the FERC complaint cases.

Ameren Missouri

Ameren Missouri has a FAC cost recovery mechanism that allows Ameren Missouri to recover, 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 review. Net energy costs, as defined in the FAC, include fuel and purchased power costs, including transportation, net of off-system sales. As of May 30, 2015, transmission revenues and substantially all transmission charges are excluded from net energy costs as a result of the April 2015 MoPSC electric rate order, which unfavorably affected margins as discussed below. Ameren Missouri accrues, as a regulatory asset, net energy costs that exceed the amount set in base rates (FAC under-recovery). Net recovery of these costs through customer rates does not affect Ameren Missouri’s electric margins, as increases or decreases in revenue are offset by a corresponding increase or decrease in fuel expense to reduce the previously recognized FAC regulatory asset.

Ameren Missouri's electric margins increased $50 million, or 6%, and $28 million, or 1%, for the three and nine months ended September 30, 2015, respectively, compared with the year-ago periods. The following items had a favorable effect on Ameren Missouri's electric margins for the three and nine months ended September 30, 2015, compared with the year-ago periods:

•

Higher electric base rates, effective May 30, 2015, as a result of the April 2015 MoPSC electric rate order, which increased margins by an estimated $12 million and $16 million, respectively. The change in electric base rates is the sum of the change in base rates (estimate) (+$42 million and +$57 million, respectively) and the change in effect of higher net energy costs included in base rates (-$30 million and -$41 million, respectively) in the above table.

•

Temperatures were warmer as cooling degree-days increased 16% and 7%, respectively. The effect of weather increased margins by an estimated $28 million and $11 million, respectively. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$34 million and +$10 million, respectively) and the effect of weather (estimate) on fuel and purchased power (-$6 million and +$1 million, respectively) in the above table. Due to differences in seasonal margins and the timing of weather experienced in the first nine months of 2015, compared with the year-ago period, the effect of weather increased electric revenue and decreased fuel and purchased power costs.

•

Higher revenues associated with the MEEIA energy efficiency program cost recovery mechanism (+$4 million and +$2 million, respectively) and net shared benefits (+$4 million and +$8 million, respectively), which increased revenues by a combined $8 million and $10 million, respectively. The higher revenues were driven by the mix of company-sponsored energy efficiency measures, which led to higher recovery of lost revenues. Net shared benefits help compensate Ameren Missouri for lower sales from energy efficiency-related volume reductions in current and future periods. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency program costs.


•	Increased gross receipts taxes, which increased revenues by $5 million and $7 million, respectively, due primarily to higher electric base rates. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.

The following items had an unfavorable effect on Ameren Missouri's electric margins for the three and nine months ended September 30, 2015, compared with the year-ago periods:

•

Lower sales volumes primarily caused by the MEEIA programs and other customer energy efficiency measures, and a reduction in Noranda sales volumes. Excluding the estimated effect of weather and reduced sales to Noranda, total retail sales volumes decreased 1% for both periods, which decreased revenues by $6 million and $18 million, respectively. A reduction in Noranda sales volumes decreased revenues by $4 million and $10 million, respectively. Lower sales volumes led to a decrease in net energy costs of $8 million and $16 million, respectively. The change in net energy costs is the sum of the change in off-system sales and transmission services revenues (-$1 million and -$3 million, respectively) and the change in energy costs (+$9 million and +$19 million, respectively) in the above table.

•

As a result of the April 2015 MoPSC electric rate order, transmission revenues and substantially all transmission charges are excluded from the FAC beginning May 30, 2015, which decreased margins by $3 million and $4 million, respectively. The change in margins as a result of changes to the FAC is the sum of FAC exclusion of transmission services expenses (-$4 million and -$5 million, respectively) and transmission services revenues (+$1 million for both periods) in the above table.

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

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

Ameren Illinois

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

The provisions of the IEIMA and the FERC’s electric transmission formula rate framework provide for annual reconciliations of the electric delivery and electric transmission service revenue requirements necessary to reflect the actual costs incurred in a given year with the revenue requirements in customer rates for that year, including an allowed return on equity. See Operations and Maintenance Expenses in this section for additional information regarding the components of the revenue requirements. In each of those electric jurisdictions, if the current year's revenue requirement is greater than the revenue

requirement reflected in that year’s customer rates, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional costs from customers within the next two years. In each jurisdiction, if the current year's revenue requirement is less than the revenue requirement reflected in that year’s customer rates, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within the next two years. The increases or reductions to electric operating revenues are shown in base rates (estimate) and transmission services revenues, in the above table, for the electric delivery and electric transmission service revenues, respectively. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding Ameren Illinois' revenue requirement reconciliation pursuant to the IEIMA.

Ameren Illinois' electric margins increased $56 million, or 16%, and $93 million, or 10%, for the three and nine months ended September 30, 2015, respectively, compared with the year-ago periods. The following items had a favorable effect on Ameren Illinois’ electric margins for the three and nine months ended September 30, 2015, compared with the year-ago periods (except where a specific period is referenced):


•	Electric delivery service revenues increased by an estimated $20 million and $35 million, respectively, primarily due to increased rate base and higher recoverable costs under formula ratemaking pursuant to the IEIMA, but were reduced by a lower return on equity for electric delivery service investments due to a reduction in 30-year United States Treasury bond yields.

•

Transmission services revenues increased by $2 million and $15 million, respectively. The increases were due to a higher electric transmission services revenue requirement driven primarily by increased rate base investment and recoverable costs under forward-looking formula ratemaking, but were reduced by the recognition of a potential refund to customers based on the pending FERC complaint cases regarding the allowed base return on common equity.


•	In January 2015, the ICC issued an order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism. Based on this January 2015 order, Ameren Illinois recorded a $15 million increase to electric revenues in the first nine months of 2015, compared with the year-ago period.


•	The implementation of redesigned seasonal electric delivery service rates that became effective in January 2015 increased revenues by $11 million for the three months ended September 30, 2015, compared with the year-ago period. These redesigned delivery service rates have an effect on quarterly earnings comparisons but are not expected to materially affect annual margins.

•

A net increase in recovery of bad debt charge-offs, customer energy efficiency program costs, and environmental remediation costs through rate-adjustment mechanisms, which increased revenues by $4 million and $10 million, respectively. See Other Operations and Maintenance Expenses in this section for information on a related offsetting net increase in bad debt, customer energy efficiency, and environmental remediation costs.

•

Temperatures were warmer as cooling degree-days increased 29% and 16%, respectively. The effect of weather increased margins by an estimated $8 million and $5 million, respectively. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$8 million and +$1 million, respectively) and the effect of weather (estimate) on fuel and purchased power (flat and +$4 million, respectively) in the above table. Due to differences in seasonal margins and the timing of weather experienced in the first nine months of 2015, compared with the year-ago period, the effect of weather increased electric revenue and decreased purchased power costs.


•	Excluding the estimated effect of weather, total retail sales volumes increased 1% in the three months ended September 30, 2015, compared with the year-ago period, and residential and commercial sales volumes increased 1% in the nine months ended September 30, 2015, compared with the year-ago period, which increased revenues by an estimated $6 million and $2 million, respectively.

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

Ameren Illinois' natural gas margins decreased $2 million, or 2%, and $9 million, or 3%, for the three and nine months ended September 30, 2015, respectively, compared with the year-ago periods. The following items had an unfavorable effect on Ameren Illinois’ natural gas margins for the three and nine months ended September 30, 2015, compared with the year-ago periods (except where a specific period is referenced):


•	Decreased gross receipts taxes due primarily to lower revenues as a result of lower natural gas prices and sales volumes, which decreased revenues by $4 million in the first nine months of 2015, compared with the year-ago period. See Taxes Other Than Income Taxes in this section for information on a related offsetting decrease to gross receipts taxes.

•

Winter temperatures in 2015 were warmer compared to 2014, as heating degree-days decreased 12%, which decreased margins by an estimated $3 million in the first nine months of 2015, compared with the year-ago period. The change in margins due to weather is the sum of the effect of weather (estimate) on natural gas revenues (-$29 million) and the effect of weather (estimate) on gas purchased for resale (+$26 million) in the above table.

•

A net decrease in recovery of bad debt charge-offs, customer energy efficiency program costs, and environmental remediation costs through rate-adjustment mechanisms, which decreased revenues by $1 million and $3 million, respectively. See Other Operations and Maintenance Expenses in this section for the related offsetting net decrease in bad debt, customer energy efficiency, and environmental remediation costs.

Other Operations and Maintenance Expenses

Ameren Corporation

Other operations and maintenance expenses were $26 million higher in the third quarter of 2015, as compared with the third quarter of 2014, primarily due to increased expenses at Ameren Missouri and Ameren Illinois, as discussed below.

Other operations and maintenance expenses were $25 million higher in the first nine months of 2015, as compared with the first nine months of 2014, primarily due to increased expenses at Ameren Illinois, as discussed below.

Ameren Missouri

Other operations and maintenance expenses were $7 million higher in the third quarter of 2015, as compared with the third quarter of 2014. Other operations and maintenance expenses were comparable in the first nine months of 2015 with the first nine months of 2014. The following items increased other operations and maintenance expenses for the three and nine months ended September 30, 2015, compared with the year-ago periods (except where a specific period is referenced):


•	Amortization of previously deferred solar rebate costs, as a result of the April 2015 MoPSC electric rate order ($7 million and $10 million, respectively). Electric revenues from customer billings increased by a corresponding amount, with no overall effect on net income.


•	An unrealized MTM loss in 2015 compared with a gain in 2014, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans ($3 million and $4 million, respectively).


•	An increase in energy center maintenance costs, primarily due to more major outages at coal-fired energy centers ($3 million for the nine months ended September 30, 2015).


•	An increase in electric distribution maintenance expenditures, primarily related to increased system repair work ($3 million for the nine months ended September 30, 2015).


•	An increase in customer energy efficiency program costs due to planned MEEIA spending in 2015 ($4 million and $2 million, respectively). Electric revenues from customer billings increased by a corresponding amount, with no overall effect on net income.

The following items decreased other operations and maintenance expenses for the three and nine months ended September 30, 2015, compared with the year-ago periods (except where a specific period is referenced):


•	A reduction in disposal costs of low-level radioactive nuclear waste ($8 million for the nine months ended September 30, 2015).


•	A decrease in bad debt expense due to improved customer collections ($6 million for the nine months ended September 30, 2015).


•	A decrease in employee benefit costs, primarily due to a change in pension and postretirement expenses allowed in rates, as a result of the April 2015 MoPSC electric rate order ($4 million in both periods). Electric revenues from customer billings decreased by a corresponding amount, with no overall effect on net income.


•	A reduction in refueling and maintenance outage costs at the Callaway energy center, primarily due to preparation costs for the 2014 scheduled outage that began in October. There is no 2015 scheduled outage. ($3 million in both periods).

Ameren Illinois

Pursuant to the provisions of the IEIMA’s and the FERC’s electric transmission formula rate framework, recoverable electric service costs that are not recovered through separate cost recovery mechanisms are included in Ameren Illinois’ revenue requirement reconciliations, which result in corresponding adjustments to electric operating revenues, with no overall effect on net income. These recoverable electric service costs include other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes.

Other operations and maintenance expenses were $17 million higher and $26 million higher in the third quarter and the first nine months of 2015, respectively, as compared with the same periods in 2014. The following items increased other operations and maintenance expenses for the three and nine months ended September 30, 2015, compared with the year-ago periods (except where a specific period is referenced):


•	An increase in electric delivery maintenance expenditures, primarily related to increased circuit maintenance and system repair work as a result of regulatory compliance requirements ($7 million and $9 million, respectively).


•	An increase in bad debt, customer energy efficiency, and environmental remediation costs ($3 million and $7 million, respectively). These expenses are included in cost riders that result in additional electric and natural gas revenues, resulting in no overall effect on net income.


•	An increase in employee benefit costs, primarily due to higher pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets ($2 million and $7 million, respectively).


•	An increase in labor costs, primarily because of staff additions to comply with the requirements of the IEIMA and wage increases ($4 million and $6 million, respectively).


•	An unrealized MTM loss in 2015 compared with a gain in 2014, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans ($2 million in both periods).

Other operations and maintenance expenses decreased for the nine months ended September 30, 2015, compared with the year-ago periods, because of a $3 million decrease in natural gas compliance expenditures, primarily related to the timing of pipeline integrity work.

Provision for Callaway Construction and Operating License

Due primarily to changes in vendor support for licensing efforts at the NRC, Ameren Missouri’s assessment of long-term capacity needs, declining costs of alternative generation technologies, and the regulatory framework in Missouri, Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway energy center site. As a result of this decision, in the second quarter of 2015, Ameren and Ameren Missouri recognized a $69 million noncash pretax provision for all of the previously capitalized costs of the COL. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for additional information.

Depreciation and Amortization

Ameren Corporation

Depreciation and amortization expenses increased $14 million and $43 million in the third quarter and the first nine months of 2015, respectively, as compared with the same periods in 2014, due to increased expenses at Ameren Missouri and Ameren Illinois, as discussed below.

Ameren Missouri

Depreciation and amortization expenses increased $7 million and $16 million in the third quarter and the first nine months of 2015, respectively, primarily due to multiple significant electric capital projects completed in 2014 and increased depreciation rates resulting from the April 2015 MoPSC electric rate order.

Ameren Illinois

Depreciation and amortization expenses increased $8 million and $27 million in the third quarter and the first nine months of 2015, respectively, primarily due to electric delivery and transmission capital additions and amortization of natural gas software.

Taxes Other Than Income Taxes

Ameren Corporation

Taxes other than income taxes increased $7 million in both the third quarter and the first nine months of 2015, as compared with the same periods in 2014, primarily due to increased expenses at Ameren Missouri, partially offset by decreased expenses at Ameren Illinois, as discussed below.

Ameren Missouri

Taxes other than income taxes increased $8 million and $14 million in the third quarter and the first nine months of 2015, respectively, primarily due to increased property taxes resulting from both higher tax rates and assessed property tax values, and increased gross receipts taxes resulting from higher electric service rates. Electric revenues for gross receipts taxes from customer billings increased by a corresponding amount, with no overall effect on net income. See Excise Taxes in Note 1 - Summary of Significant Accounting Policies under Part I, Item 1, of this report for additional information.

Ameren Illinois

Taxes other than income taxes decreased $2 million in the third quarter of 2015, primarily due to a reduction in the electric distribution tax. Taxes other than income taxes decreased $8 million in the first nine months of 2015, primarily due to decreased gross receipts taxes resulting from lower natural gas sales prices and volumes, and a reduction in the electric distribution tax. Natural gas revenues for gross receipts taxes from customer billings decreased by a corresponding amount, with no overall effect on net income.

Other Income and Expenses

Ameren Corporation

Other income, net of expenses, was comparable in the third quarter of 2015 with the third quarter of 2014. Other income, net of expenses, decreased $8 million in the first nine months of 2015, as compared with the first nine months of 2014, primarily due to items at Ameren Missouri, as discussed below. See Note 5 - Other Income and Expenses under Part I, Item 1, of this report for additional information.

Ameren Missouri

Other income, net of expenses, was comparable in the third quarter of 2015 with the third quarter of 2014. Other income, net of expenses, decreased $6 million in the first nine months of 2015, primarily because of a decrease in the allowance for equity funds used during construction, as multiple significant electric capital projects were completed in 2014.

Ameren Illinois

Other income, net of expenses, was comparable in both the third quarter and the first nine months of 2015 with the same periods in 2014.

Interest Charges

Ameren Corporation

Interest charges increased $2 million in the third quarter of 2015, as compared with the third quarter of 2014, primarily due to increased interest expenses at Ameren Illinois, as discussed below.

Interest charges decreased $2 million in the first nine months of 2015, as compared with the first nine months of 2014. Interest charges at Ameren (parent) decreased by $16 million, primarily resulting from a decrease related to long-term debt offset by an increase related to short-term debt, as short-term debt levels increased in 2015. In May 2014, Ameren (parent) repaid at maturity $425 million of its 8.875% senior unsecured notes, which were replaced with lower-cost short-term debt. The reduction at Ameren (parent) was offset by increases in interest expenses at Ameren Missouri and Ameren Illinois, as discussed below.

Ameren Missouri

Interest charges were comparable in the third quarter of 2015 with the third quarter of 2014. Interest charges increased $5 million in the first nine months of 2015, primarily because of a decrease in the allowance for funds used during construction, as multiple significant electric capital projects were completed in 2014, and due to the issuance of senior secured notes in April 2015.

Ameren Illinois

Interest charges increased $2 million in the third quarter of 2015, primarily due to the issuance of senior secured notes in December 2014. Interest charges increased $9 million in the first nine months of 2015, primarily due to the issuances of senior secured notes in June 2014 and in December 2014.

Income Taxes

The following table presents effective income tax rates for the three and nine months ended September 30, 2015 and 2014:



	Three Months^(a)				Nine Months^(a)
	2015		2014		2015		2014
Ameren	38	%	40	%	38	%	40	%
Ameren Missouri	37	%	37	%	37	%	37	%
Ameren Illinois	38	%	42	%	38	%	41	%


(a)	Based on the current estimate of the annual effective tax rate adjusted to reflect the tax effect of items discrete to the relevant period.

Ameren Corporation

The effective tax rate was lower in the third quarter of 2015, as compared with the third quarter of 2014, primarily due to a reduced Illinois state statutory rate in 2015, decreased tax expense related to stock-based compensation, decreased non-deductible expenditures, and higher tax benefits from certain property-related items.

The effective tax rate was lower in the first nine months of 2015, as compared with the first nine months of 2014, primarily due to lower Illinois state income tax expense in 2015 resulting from a reduced statutory rate, along with decreased tax expense related to stock-based compensation.

Ameren Missouri

The effective tax rate was comparable in the third quarter and the first nine months of 2015 with the same periods in 2014.

Ameren Illinois

The effective tax rate was lower in the third quarter and the first nine months of 2015, as compared with the same periods in 2014, primarily due to a reduced Illinois state statutory rate in 2015, along with decreased non-deductible expenditures in 2015, as well as higher tax benefits from certain property-related items.

Income (Loss) from Discontinued Operations, Net of Taxes

No material activity was recorded during the three months ended September 30, 2015. During the nine months ended September 30, 2015, based on completion of the IRS audit of Ameren’s 2013 tax year, Ameren recognized a tax benefit of $53 million due to the resolution of an uncertain tax position from discontinued operations. No material activity was recorded in either 2014 period. See Note 1 - Summary of Significant Accounting Policies and Note 12 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for additional information.

LIQUIDITY AND CAPITAL RESOURCES

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

The use of cash from operating activities and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at September 30, 2015, for Ameren and Ameren Illinois. The working capital deficit as of September 30, 2015, was primarily the result of increased commercial paper issuances and the use of other forms of short-term debt. With the 2012 Credit Agreements and cash and cash equivalents available, the Ameren Companies have access to $2.1 billion of credit capacity, and $1.4 billion of liquidity at September 30, 2015.

The following table presents net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2015 and 2014:



	Net Cash Provided By (Used In) Operating Activities								Net Cash Provided by (Used In) Investing Activities									Net Cash Provided by (Used In) Financing Activities
	2015			2014			Variance		2015			2014			Variance			2015			2014			Variance
Ameren^(a) - continuing operations	$	1,533		$	1,208		$	325	$	(1,362	)	$	(1,351	)	$	(11	)	$	(99	)	$	(8	)	$	(91	)
Ameren^(a) - discontinued operations	(5		)	(5		)	—		—			139			(139		)	—			—			—
Ameren Missouri	1,040			660			380		(739		)	(593		)	(146		)	(233		)	(67		)	(166		)
Ameren Illinois	541			396			145		(615		)	(627		)	12			73			231			(158		)


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

Cash Flows from Operating Activities

Ameren Corporation

Ameren’s cash from operating activities associated with continuing operations increased $325 million in the first nine months of 2015, compared with the same period in 2014. The following items contributed to the increase:


•	A $108 million increase in cash associated with Ameren Illinois' IEIMA revenue requirement reconciliation adjustments as Ameren Illinois collected $55 million from customers in 2015 and refunded $53 million to customers in 2014.


•	A $99 million increase in net energy costs collected from Ameren Missouri customers under the FAC.


•	A $76 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 $56 million decrease in Ameren Missouri rebate payments provided for customer-installed solar generation as the rebate program was substantially completed by the end of 2014.


•	A $49 million decrease in the cost of natural gas held in storage caused primarily by lower purchased gas prices.


•	A $39 million decrease in pension and postretirement benefit plan contributions caused by the timing of payments.


•	A $23 million increase in natural gas commodity costs collected from customers under the PGAs, primarily related to Ameren Illinois.


•	A $6 million decrease in payments to purchase stock associated with equity compensation plan awards.

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


•	A $36 million increase in coal inventory costs at Ameren Missouri caused by increased volumes resulting from the absence of weather-related railroad delivery delays that occurred in 2014.


•	A $31 million increase in purchased power commodity costs paid compared with amounts collected from Ameren Illinois customers.


•	A $20 million increase in expenditures for customer energy efficiency programs compared with amounts collected from Ameren Illinois customers.


•	A net $20 million decrease in returns of collateral posted with counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes, partially offset by the effect of credit rating upgrades.


•	A $12 million reduction in income tax refunds due to the absence in 2015 of tax credit sales.


•	A $7 million increase in property tax payments at Ameren Missouri caused by both higher assessed property tax values and tax rates.

Ameren’s cash from operating activities associated with discontinued operations was comparable between periods.

Ameren Missouri

Ameren Missouri’s cash from operating activities increased $380 million in the first nine months of 2015, compared with the same period in 2014. The following items contributed to the increase:


•	A $275 million decrease in income taxes paid to Ameren (parent) pursuant to the tax allocation agreement, primarily related to a change in the tax treatment for generation repairs adopted in 2013, which increased payments in 2014.


•	A $99 million increase in net energy costs collected from customers under the FAC.


•	A $56 million decrease in rebate payments provided for customer-installed solar generation as the rebate program was substantially completed by the end of 2014.


•	A $16 million decrease in pension and postretirement benefit plan contributions caused by the timing of payments.


•	An $8 million decrease in the cost of natural gas held in storage caused by lower purchased gas prices.


•	A $6 million increase in natural gas commodity costs collected from customers under the PGA.

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


•	A $36 million increase in coal inventory costs caused by increased volumes resulting from the absence of weather-related delivery delays that occurred in 2014.


•	A net $8 million decrease in returns of collateral posted with counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes, partially offset by the effect of credit rating upgrades.


•	A $7 million increase in property tax payments caused by both higher assessed property tax values and tax rates.

Ameren Illinois

Ameren Illinois’ cash from operating activities increased $145 million in the first nine months of 2015, compared with the same period in 2014. The following items contributed to the increase:


•	A $108 million increase in cash associated with IEIMA revenue requirement reconciliation adjustments as $55 million was collected from customers in 2015 and $53 million was refunded to customers in 2014.


•	A $43 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 $41 million decrease in the cost of natural gas held in storage caused primarily by lower purchased gas prices.


•	A $17 million increase in natural gas commodity costs collected from customers under the PGA.


•	A $16 million decrease in pension and postretirement benefit plan contributions caused by the timing of payments.

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


•	A $31 million increase in purchased power commodity costs incurred compared with amounts collected from customers.


•	A $20 million increase in expenditures for customer energy efficiency programs compared with amounts collected from customers.


•	A $20 million reduction in income tax refunds primarily due to higher pre-tax income during 2015.


•	A net $12 million decrease in returns of collateral posted with counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes, partially offset by the effect of credit rating upgrades.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities associated with continuing operations increased $11 million in the first nine months of 2015, compared with the same period in 2014. Capital expenditures increased $22 million as a result of a $144 million increase in ATXI’s capital expenditures, which primarily related to the Illinois Rivers project, offset by the activity at Ameren Missouri and Ameren Illinois, as discussed below.

No cash from investing activities was provided by or used for discontinued operations during 2015. In the nine months ended September 30, 2014, Ameren’s cash provided by investing activities associated with discontinued operations consisted of

$152 million received for the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers in January 2014, offset by payment of $13 million to IPH for the final working capital adjustment and a portion of certain contingent liabilities associated with the New AER divestiture.

Ameren Missouri’s cash used in investing activities increased $146 million, primarily due to a $250 million money pool advance, partially offset by decreased transmission and distribution system reliability and energy center capital expenditures.

Ameren Illinois’ cash used in investing activities decreased $12 million due to a decrease in capital expenditures for transmission projects offset, in part, by increases in IEIMA electric distribution projects. While spending related to transmission projects decreased during the first nine months of 2015, compared to the prior-year period, capital expenditures related to transmission projects for calendar year 2015 are expected to exceed calendar year 2014 amounts.

Ameren estimates its capital expenditures from 2015 through 2019 will be $8.6 billion to $9.3 billion, with $2.0 billion expected in 2015. During the nine months ended September 30, 2015, Ameren’s capital expenditures totaled $1.3 billion. Ameren is currently evaluating potential capital expenditures at Ameren Illinois of an estimated $500 million to $1 billion that are incremental to the estimate above. Ameren will continue to evaluate these investment opportunities as a part of its normal annual planning process.

Ameren Missouri continually reviews its generation portfolio and expected power needs. As a result, Ameren Missouri could modify its plan for generation capacity, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other changes. Additionally, we continually review the reliability of our transmission and distribution systems, expected capacity needs, and opportunities for transmission investments. The timing and amount of investments could vary because of changes in expected capacity, the condition of transmission and distribution systems, changes in laws or regulations, and our ability and willingness to pursue transmission investments, among other factors. Any changes in future generation, transmission, or distribution needs could result in significant capital expenditures or impairment losses, which could be material. Compliance with environmental regulations could also have significant impacts on the level of capital expenditures. See Note 9 - Commitments and Contingencies in Part I, Item 1, of this report for additional information.

Cash Flows from Financing Activities

Ameren’s cash used in financing activities associated with continuing operations increased $91 million during the first nine months of 2015, compared with the same period in 2014. The increase in cash used in financing activities resulted from decreased net borrowing activity. During the first nine months of 2015 and 2014, Ameren used cash generated from operating activities to fund investing and financing activities and, in 2015, to

increase its cash balance. In addition, Ameren Missouri issued and redeemed long-term debt during the first nine months of 2015 and 2014. Ameren Illinois issued and redeemed long-term debt during the first nine months of 2014.

No cash from financing activities was used for discontinued operations during 2015 or 2014.

Ameren Missouri’s cash used in financing activities increased $166 million during the first nine months of 2015, compared with the same period in 2014. In the first nine months of 2015, Ameren Missouri received a capital contribution from Ameren (parent) of $224 million, repaid a net $97 million of short-term debt, paid common stock dividends of $490 million, redeemed $114 million in long term-debt, and received proceeds of $249 million from a long-term debt issuance. During the first nine months of 2015, Ameren Missouri used a portion of its cash generated from operating activities to fund investing and financing activities. In 2014, Ameren Missouri issued a net $65 million of short-term debt, repaid a net $105 million to the money

pool, paid common stock dividends of $268 million, redeemed long-term debt of $104 million, and received proceeds of $350 million from a long-term debt issuance. During the first nine months of 2014, Ameren Missouri used cash generated from operating activities and cash on hand to fund investing and financing activities.

Ameren Illinois’ cash provided by financing activities decreased $158 million during the first nine months of 2015, compared with the same period in 2014. In the first nine months of 2015, Ameren Illinois repaid a net $32 million of short-term debt and borrowed a net $107 million from the money pool. During the first nine months of both 2015 and 2014, Ameren Illinois used cash from financing activities to fund investing activities that were not funded by cash generated from operating activities. In 2014, Ameren Illinois borrowed a net $189 million of short-term debt, repaid a net $40 million to the money pool, redeemed long-term debt of $163 million, and received proceeds of $248 million from a long-term debt issuance.

Credit Facility Borrowings and Liquidity

The liquidity needs of Ameren, Ameren Missouri, and Ameren Illinois are typically supported through the use of available cash, short-term intercompany borrowings, drawings under committed credit agreements or commercial paper issuances. See Note 3 - Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information on credit agreements, 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, 2015:



	Available at September 30, 2015
Ameren and Ameren Missouri:
2012 Missouri Credit Agreement - borrowing capacity ^(a)	$	1,000
Less: Ameren (parent) commercial paper outstanding	457
2012 Missouri Credit Agreement - credit available	543
Ameren and Ameren Illinois:
2012 Illinois Credit Agreement - borrowing capacity ^(a)	1,100
Less: Ameren (parent) commercial paper outstanding	326
Less: Letters of credit ^(b)	13
2012 Illinois Credit Agreement - credit available	761
Total Credit Available	$	1,304
Cash and cash equivalents	72
Total Liquidity	$	1,376


(a)	Expires in December 2019.


(b)	As of September 30, 2015, $9 million of the letters of credit related to Ameren's credit support obligations to New AER. See Note 12 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for additional information.

The 2012 Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs. Either of the 2012 Credit Agreements are available to Ameren to support issuances under Ameren’s commercial paper program, subject to borrowing sublimits. The 2012 Missouri Credit Agreement is available to support issuances under Ameren Missouri’s commercial paper program. The 2012 Illinois Credit Agreement is available to support issuances under Ameren Illinois’ commercial paper program. Issuances under the Ameren, Ameren Missouri, and Ameren Illinois commercial paper programs were available at lower interest rates than the interest

rates available under the 2012 Credit Agreements. As such, commercial paper issuances were a preferred source of third-party short-term debt relative to credit facility borrowings.

In addition, Ameren Missouri and Ameren Illinois may borrow cash from the utility money pool when funds are available. The rate of interest depends on the composition of internal and external funds in the utility money pool. Ameren Missouri and Ameren Illinois borrow from the utility money pool when funds are available before utilizing the 2012 Credit Agreements and commercial paper programs because the utility money pool interest rates are lower.

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 July 2015, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities through July 14, 2017.

The Ameren Companies continually evaluate the adequacy

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

Long-term Debt and Equity

The following table presents the issuances (net of any issuance discounts), maturities, and redemptions of long-term debt for the Ameren Companies for the nine months ended September 30, 2015 and 2014. The Ameren Companies did not have any issuances of common stock during the first nine months of 2015 or 2014. In March 2015, Ameren Missouri received cash capital contributions of $224 million from Ameren (parent). For additional information, see Note 4 - Long-term Debt and Equity under Part I, Item 1, of this report.



	Month Issued, Redeemed, or Matured	2015		2014
Issuances
Long-term debt
Ameren Missouri:
3.65% Senior secured notes due 2045	April	$	249	$	—
3.50% Senior secured notes due 2024	April	—		350
Ameren Illinois:
4.30% Senior secured notes due 2044	June	—		248
Total Ameren long-term debt issuances		$	249	$	598
Redemptions and Maturities
Long-term debt
Ameren (parent):
8.875% Senior unsecured notes due 2014	May	$	—	$	425
Ameren Missouri:
4.75% Senior secured notes due 2015	April	114		—
5.50% Senior secured notes due 2014	May	—		104
Ameren Illinois:
5.90% Series 1993 due 2023^(a)	January	—		32
5.70% 1994A Series due 2024^(a)	January	—		36
5.95% 1993 Series C-1 due 2026	January	—		35
5.70% 1993 Series C-2 due 2026	January	—		8
5.40% 1998A Series due 2028	January	—		19
5.40% 1998B Series due 2028	January	—		33
Total Ameren long-term debt redemptions and maturities		$	114	$	692

(a)Less than $1 million principal amount of the bonds remain outstanding after redemption.

In June 2015, Ameren, Ameren Missouri, and Ameren Illinois filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities. The registration statement became effective immediately upon filing and will expire in June 2018.

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

Indebtedness Provisions and Other Covenants

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

in certain of the Ameren Companies’ indentures and articles of incorporation.

At September 30, 2015, the Ameren Companies were in compliance with the provisions and covenants contained within their credit agreements, indentures, and articles of incorporation.

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

Dividends

The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. Ameren’s board of directors has not set specific targets or payout parameters when declaring common stock dividends but considers various factors, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. Ameren expects its dividend payout ratio to be between 55% and 70% of earnings over the next few years. On October 9, 2015, Ameren’s board of

directors declared a quarterly common stock dividend of 42.5 cents per share payable on December 31, 2015, to stockholders of record on December 9, 2015, resulting in an annualized equivalent dividend rate of $1.70 per share. The previous annualized equivalent dividend rate was $1.64 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, 2015, 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 stockholders and by Ameren Missouri and Ameren Illinois to their parent, Ameren Corporation, for the nine months ended September 30, 2015 and 2014:



	Nine Months
	2015		2014
Ameren Missouri	$	490	$	268
Ameren Illinois	—		—
Ameren	298		291

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.

Off-Balance-Sheet Arrangements

At September 30, 2015, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future. See Note 12 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for Ameren (parent) guarantees and letters of credit issued to support New AER based on the transaction agreement with IPH.

Credit Ratings

The credit ratings of the Ameren Companies affect our liquidity, access to the capital markets and credit markets, cost of borrowing under credit facilities, and collateral posting requirements under commodity contracts.

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



	Moody’s	S&P	Fitch
Ameren:
Issuer/corporate credit rating	Baa1	BBB+	BBB+
Senior unsecured debt	Baa1	BBB	BBB+
Commercial paper	P-2	A-2	F2
Ameren Missouri:
Issuer/corporate credit rating	Baa1	BBB+	BBB+
Secured debt	A2	A	A
Senior unsecured debt	Baa1	BBB+	A-
Commercial paper	P-2	A-2	F2
Ameren Illinois:
Issuer/corporate credit rating	A3	BBB+	BBB+
Secured debt	A1	A	A
Senior unsecured debt	A3	BBB+	A-
Commercial paper	P-2	A-2	F2

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

Collateral Postings

Any adverse change in 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 a potential negative impact on earnings. Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, at September 30, 2015, were $10 million, $9 million, and $1 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively. At September 30, 2015, cash collateral posted by external counterparties with Ameren and Ameren Illinois was $5 million. Sub-investment-grade issuer or senior unsecured debt rating (lower than “BBB-” or “Baa3”) at September 30, 2015, 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 $150 million, $75 million, or $75 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at September 30, 2015, if market prices were 15% higher than September 30, 2015 levels in the next 12 months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois would not be required to post additional collateral or other assurances for certain trade obligations. Based on credit ratings at September 30, 2015, if market prices were 15% lower than September 30, 2015 levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois could be required to post additional collateral or other assurances for certain trade obligations up to $27 million, $12 million, and $15 million, respectively.

See Note 12 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for information regarding Ameren (parent) guarantees.

OUTLOOK

We seek to earn competitive returns on investments in our businesses. We are seeking to improve our regulatory frameworks and cost recovery mechanisms and simultaneously pursuing constructive regulatory outcomes within existing frameworks. We are seeking to align our overall spending, both operating and capital, with economic conditions and with regulatory frameworks established by our regulators. Consequently, we are focused on minimizing the gap between allowed and earned returns on equity. We intend to allocate capital resources to our business opportunities that offer the most attractive risk-adjusted return potential.

Below are some key trends, events, and uncertainties that are reasonably likely to affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 2015 and beyond.

Operations


•	Our strategy for earning competitive returns on our investments involves meeting customer energy needs in an efficient fashion, working to enhance regulatory frameworks, making timely and well-supported rate case filings, and aligning overall spending with those rate case outcomes, economic conditions, and return opportunities.

•

Ameren continues to pursue its plans to invest in FERC-regulated electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The first project, Illinois Rivers, involves the construction of a transmission line from western Indiana across the state of Illinois to eastern Missouri. The first sections of the Illinois Rivers project are expected to be completed in 2016. The last section of this project is expected to be completed by 2019. The Spoon River project in northwest Illinois and the Mark Twain project in northeast Missouri are the other two MISO-approved projects to be constructed by ATXI. These two projects are expected to be completed in 2018. The total investment in these three projects is expected to be more than $1.4 billion during 2015 through 2019. This total includes over $100 million of investment by Ameren Illinois to construct connections to its existing transmission system. Separate from the three projects discussed above, Ameren Illinois expects to invest approximately $900 million in electric transmission assets during 2015 through 2019 to address load growth and reliability requirements. The Ameren Illinois projects discussed above do not include potential additional capital investments for 2016 through 2019 that are currently being evaluated as part of our normal annual planning process and are discussed in the Liquidity and Capital Resources section below.


•	Both Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Using the rates that will become effective on

January 1, 2016, and the currently allowed 12.38% return on equity, the 2016 revenue requirement for Ameren Illinois’ electric transmission business would be $242 million, which represents a $43 million increase over the 2015 revenue requirement due to rate base growth. These rates reflect a capital structure composed of 51.9% common equity and a projected rate base of $1.2 billion. Using the rates that will become effective on January 1, 2016, and the currently allowed 12.38% return on equity, the 2016 revenue requirement for ATXI’s electric transmission business would be $138 million, which represents a $58 million increase over the 2015 revenue requirement due to rate base growth, primarily as a result of the Illinois Rivers project. These rates reflect a capital structure composed of 56.1% common equity and a projected rate base of $887 million.

•

The 12.38% return on common equity is the subject of two FERC complaint proceedings that challenge the allowed base return on common equity for MISO transmission owners. The FERC scheduled hearing procedures for both the November 2013 complaint case and the February 2015 complaint case, requiring a proposed order from its administrative law judge in each case no later than November 30, 2015 and June 30, 2016, respectively. 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 $5 million and $3 million, respectively, based on each company’s 2016 projected rate base. Ameren and Ameren Illinois recorded current regulatory liabilities on their respective balance sheets as of September 30, 2015, representing their estimate of the potential refunds from the November 12, 2013 refund effective date.

•

On January 6, 2015, a FERC-approved incentive adder of up to 50 basis points on the allowed base return on common equity for our participation in an RTO became effective. Upon the issuance of the final order addressing the initial MISO complaint case discussed above, beginning with its January 6, 2015 effective date, the incentive adder will reduce any refund to customers relating to a reduction of the base return on common equity.

•

In April 2015, the MoPSC issued an order approving an increase in Ameren Missouri’s annual revenues for electric service of $122 million, including $109 million related to the increase in net energy costs above those included in base rates previously authorized by the MoPSC. The revenue increase was based on a 9.53% return on common equity, a capital structure composed of 51.8% common equity, and a rate base of $7.0 billion to reflect investments through December 31, 2014. Rate changes consistent with the order became effective on May 30, 2015. Ameren Missouri’s revenue requirement, prior to May 30, 2015, was based on a 9.8% return on common equity, a capital structure composed of 52.3% common equity, and a rate base of $6.8 billion. Accordingly, the level of earnings reflected in the revenue requirement in effect after May 30, 2015, is lower than the level of earnings reflected in the previously effective revenue requirement. The order approved Ameren Missouri’s request for continued use of the FAC; however, it changed the FAC to exclude all transmission revenues and

substantially all transmission charges. In addition, the order did not approve the continued use of regulatory tracking mechanisms for storm costs and vegetation management and infrastructure inspection costs. These changes to Ameren Missouri’s recovery mechanisms are expected to contribute to regulatory lag. For example, transmission charges previously included in the FAC that are now included in base rates totaled $30 million in 2014 and are expected to increase to $41 million in 2015, with further cost increases expected in the foreseeable future. However, transmission revenues totaled $34 million in 2014 and are expected to increase annually to $36 million in 2015 and remain relatively constant in the foreseeable future.

•

Sales to Noranda represented 5% of Ameren Missouri’s total electric revenue in 2014. Sales volumes to Noranda during 2015 have been below the sales volumes assumed in the MoPSC’s April 2015 electric rate order. To the extent actual sales volumes are lower than the sales volumes assumed in determining rates due to operating or financial difficulties at Noranda, Ameren Missouri may under-recover its fixed costs until rates are adjusted by the MoPSC.

•

Ameren Missouri's current MEEIA plan provides for a cumulative investment in customer energy efficiency programs of up to $147 million during 2013 through 2015. Additionally, the plan provides for a performance incentive that would allow Ameren Missouri to earn additional revenues based on achievement of certain customer energy efficiency goals, including $19 million if 100% of the goals are achieved during the three-year period, with the potential to earn more if Ameren Missouri’s energy savings exceed those goals. In June 2015, the MoPSC staff filed a complaint case with the MoPSC regarding the method and inputs used in calculating the performance incentive. If the MoPSC agrees with the MoPSC staff’s interpretation of the August 2012 MEEIA order, the performance incentive recognized in 2016 would be significantly less than the performance incentive calculated using Ameren Missouri’s interpretation. Regardless of the MoPSC’s decision in the complaint case, Ameren Missouri believes it will exceed 100% of the customer energy efficiency goals and recognize revenues of at least $19 million associated with the performance incentive in 2016. In addition, Ameren Missouri records revenues based on the net shared benefits associated with the reduction in customer energy usage that results from its customer energy efficiency programs. From January 2013 through September 2015, Ameren Missouri has recorded revenues of $134 million, $45 million of which was recorded in 2015, associated with the net shared benefits based on the estimated megawatthour reductions provided by the MEEIA customer energy efficiency programs both in the program period and in the future. In October 2015, the MoPSC rejected Ameren Missouri’s MEEIA energy efficiency plan for 2016 through 2018. Ameren Missouri is studying the MoPSC’s October 2015 order and evaluating whether to file another proposed energy efficiency plan with the MoPSC. Ameren Missouri expects to continue to experience sales volume reductions into 2016 from the 2013 through 2015 MEEIA plan.

•

The IEIMA provides for an annual reconciliation of the revenue requirement necessary to reflect the actual recoverable costs incurred in a given year with the revenue requirement that was reflected in customer rates for that year. Consequently, Ameren Illinois' 2015 electric delivery service revenues will be based on its 2015 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. The 2015 revenue requirement is expected to be higher than the 2014 revenue requirement, due to an expected increase in recoverable costs and rate base growth, partially offset by a reduction in the allowed return on equity due to lower United States Treasury bond yields. A 50 basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $6 million change in Ameren's and Ameren Illinois' 2015 net income.

•

In December 2014, the ICC approved a $204 million increase in Ameren Illinois’ electric delivery service revenue requirement, beginning in January 2015. The resulting customer rates have affected and will continue to affect Ameren Illinois' cash receipts during 2015, but will not be the sole determinant of its electric delivery service operating revenues, which will instead be largely determined by the IEIMA's 2015 revenue requirement reconciliation. The 2015 revenue requirement reconciliation is expected to result in a regulatory asset that will be collected from customers in 2017.

•

Ameren Illinois’ annual electric delivery service formula rate update to establish customer rates for 2016 is currently pending before the ICC. If the ICC approves as filed, the annual update filing would result in a $109 million increase in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2016. This update reflects an increase to the annual formula rate based on 2014 actual recoverable costs and expected net plant additions for 2015, an increase to include the 2014 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the 2013 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2015. In October 2015, the ICC staff submitted its calculation of Ameren Illinois’ revenue requirement. The ICC staff recommended adjustments that would result in a $107 million increase in Ameren Illinois’ electric delivery service revenue requirement. An ICC decision on this update filing is required by December 2015. The resulting customer rates will affect Ameren Illinois' cash receipts during 2016, but will not be the sole determinant of its 2016 electric delivery service operating revenues, which will instead be largely determined by the IEIMA's 2016 revenue requirement reconciliation.

•

In July 2015, Ameren Illinois filed an amended request with the ICC seeking approval to increase its annual revenues for natural gas delivery service. This rate case includes a capital structure composed of 50% common equity and a rate base of $1.2 billion. In July 2015, Ameren Illinois, the ICC staff, and certain other intervenors filed a stipulation and agreement with the ICC that would result in rates that are based on a return on common equity of 9.6%. The

agreement does not address the positions of all of the parties in the rate case. Based on the terms in the agreement and the unresolved positions in the case, Ameren Illinois' request seeks an annual revenue increase of $45 million, which is consistent with the ICC staff’s recommendation and the administrative law judges' proposed order issued in November 2015. The administrative law judges' order also proposed the approval of the volume balancing adjustment. A decision by the ICC in this proceeding is required by December 2015, and new rates are expected to be effective in January 2016.

•

Ameren Missouri's next scheduled refueling and maintenance outage at its Callaway energy center will be in the spring of 2016. During the fall 2014 refueling, Ameren Missouri incurred maintenance expenses of $36 million. 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, resulting in limited impacts to earnings.

•

Ameren Missouri is engaged in litigation with an insurer to recover an unpaid liability insurance claim for the December 2005 breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity could be adversely affected if Ameren Missouri’s insurance receivable of $41 million, as of September 30, 2015, is not paid by the insurer.

•

As we continue to experience cost increases and to make infrastructure investments, Ameren Missouri and Ameren Illinois expect to seek regular electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. Ameren Missouri and Ameren Illinois will also seek, as necessary, legislative solutions to address cost recovery pressures and to support investment in their energy infrastructure. These pressures include limited economic growth in their service territories, customer conservation efforts, the impacts of additional customer energy efficiency programs, increased use of innovative and increasingly cost-effective technological advances including distributed generation and storage, increased investments and expected future investments for environmental compliance, system reliability improvements, and new generation capacity, including renewable energy requirements. Increased investments also result in higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs and higher property and income taxes, among other costs.

For additional information regarding recent rate orders and related appeals, pending requests filed with state and federal regulatory commissions, and Taum Sauk matters, see 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 and Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K.

Liquidity and Capital Resources

•

We expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure and to comply with existing environmental regulations. We estimate that we will make up to $9.3 billion (Ameren Missouri - up to $3.9 billion; Ameren Illinois - up to $4.0 billion; ATXI - up to $1.4 billion) of capital expenditures during the period from 2015 through 2019. Ameren is currently evaluating potential capital expenditures at Ameren Illinois for 2016 through 2019 of an estimated $500 million to $1 billion that are incremental to the estimates above. We will continue to evaluate these investment opportunities as a part of our normal annual planning process.

•

Environmental regulations, including those related to greenhouse gas emissions, or other actions taken by the EPA, could result in significant increases in capital expenditures and operating costs. These costs could be prohibitive at some of Ameren Missouri's coal-fired energy centers. Ameren Missouri's capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances as well as regulatory lag. The cost of Ameren Illinois’ purchased power and gas purchased for resale could increase; however, Ameren Illinois expects these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. Ameren's and Ameren Missouri's earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in rates.

•

Ameren Missouri is evaluating the Clean Power Plan and its potential implementation by Missouri and Illinois. This assessment includes the potential impacts to its operations, including those related to electric system reliability and its level of investment in customer energy efficiency programs, renewable energy generation, and other forms of generation. Under the Clean Power Plan, Ameren Missouri expects to incur increased net fuel and operating costs, and new or accelerated capital expenditures, in addition to making modifications to existing operations in order to achieve compliance. Compliance measures could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and natural gas-fired energy centers, which could result in increased operating costs.

•

Ameren Missouri files a non-binding integrated resource plan with the MoPSC every three years. Ameren Missouri’s integrated resource plan filed with the MoPSC in October 2014, prior to the issuance of the Clean Power Plan, is a 20-year plan that supports a more fuel-diverse energy portfolio in Missouri, including coal, solar, wind, natural gas and nuclear power. The plan includes expanding renewable generation, retiring coal-fired generation as energy centers reach the end of their useful lives, and adding natural gas-fired combined cycle generation. Ameren Missouri continues to study future alternatives that could help defer new energy

center construction. It is expected that this plan will need to be modified to comply with the Clean Power Plan and incorporate changes in the level of investment in customer energy efficiency programs as Ameren Missouri evaluates future MEEIA plans.


•	To fund investment requirements of our businesses, we seek to maintain access to the capital markets at commercially attractive rates. We seek to enhance regulatory frameworks and returns in order to improve liquidity, credit metrics, and access to capital.

•

The Ameren Companies have multiyear credit agreements that cumulatively provide $2.1 billion of credit through December 11, 2019, subject to a 364-day repayment term in the case of Ameren Missouri and Ameren Illinois. See Note 3 - Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information regarding the 2012 Credit Agreements. Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.

•

As of September 30, 2015, Ameren had $299 million in tax benefits from federal and state net operating loss carryforwards (Ameren Missouri - $- million and Ameren Illinois - $67 million) and $142 million in federal and state income tax credit carryforwards (Ameren Missouri - $25 million and Ameren Illinois - $1 million). 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 during 2015 and 2016, while Ameren does not expect to make material federal income tax payments until 2017. In addition, Ameren has $61 million of expected income tax refunds and state overpayments that would offset income tax liabilities into 2017. These tax benefits, primarily at the Ameren (parent) level, when realized, would be available to fund electric transmission investments, specifically ATXI's Illinois Rivers project.


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

•

In October 2015, Ameren’s board of directors declared a fourth quarter dividend of 42.5 cents per common share, a 3.7% increase from the prior quarterly dividend rate of 41 cents per share, resulting in an annualized equivalent dividend rate of $1.70 per share. On an annual basis, the dividend increase, at current outstanding common stock levels, will result in additional dividend payments of $15 million.


•	The use of cash from operating activities and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit, defined by current liabilities exceeding current assets, as was the case at September 30, 2015, for Ameren

and Ameren Illinois. The working capital deficit as of September 30, 2015, was primarily the result of increased commercial paper issuances and the use of other forms of short-term debt. The Ameren Companies had $783 million of commercial paper issuances outstanding as of September 30, 2015. With the 2012 Credit Agreements and cash and cash equivalents available, the Ameren Companies had access to $2.1 billion of credit capacity, and $1.4 billion of liquidity, at September 30, 2015.


•	Ameren (parent) and Ameren Illinois expect to issue long-term debt during the fourth quarter of 2015, to repay a substantial portion of their short-term debt. In addition, Ameren Illinois expects to pay dividends to Ameren (parent) beginning in 2016.

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, and opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren's stockholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position, or liquidity.

REGULATORY MATTERS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

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

There have been no material changes to the quantitative and qualitative disclosures about interest rate risk, credit risk, equity price risk, commodity price risk, and commodity supplier risk included in the Form 10-K. 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, 2015. 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 year, net	$	(4	)	$	(202	)	$	(206	)	$	(28	)	$	(185	)	$	(213	)
Contracts realized or otherwise settled during the period	—			12			12			11			32			43
Fair value of new contracts entered into during the period	—			(4		)	(4		)	16			(12		)	4
Other changes in fair value	(13		)	(20		)	(33		)	(16		)	(49		)	(65		)
Fair value of contracts outstanding at end of period, net	$	(17	)	$	(214	)	$	(231	)	$	(17	)	$	(214	)	$	(231	)

The following table presents maturities of derivative contracts as of September 30, 2015, 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	$	(18	)	$	(7	)	$	—		$	—		$	(25	)
Level 2^(a)	(4		)	(5		)	(2		)	—			(11		)
Level 3^(b)	19			—			—			—			19
Total	$	(3	)	$	(12	)	$	(2	)	$	—		$	(17	)
Ameren Illinois:
Level 1	$	—		$	—		$	—		$	—		$	—
Level 2^(a)	(26		)	(17		)	(1		)	—			(44		)
Level 3^(b)	(12		)	(25		)	(23		)	(110		)	(170		)
Total	$	(38	)	$	(42	)	$	(24	)	$	(110	)	$	(214	)
Ameren:
Level 1	$	(18	)	$	(7	)	$	—		$	—		$	(25	)
Level 2^(a)	(30		)	(22		)	(3		)	—			(55		)
Level 3^(b)	7			(25		)	(23		)	(110		)	(151		)
Total	$	(41	)	$	(54	)	$	(26	)	$	(110	)	$	(231	)


(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 a Black-Scholes model.

ITEM 4. CONTROLS AND PROCEDURES.


(a)	Evaluation of Disclosure Controls and Procedures

As of September 30, 2015, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on those evaluations, as of September 30, 2015, the principal executive officer and the principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and its principal financial officers, to allow timely decisions regarding required disclosure.


(b)	Changes in Internal Controls over Financial Reporting

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. Material legal and administrative proceedings, which are discussed in Note 2 - Rate and Regulatory Matters, Note 9 - Commitments and Contingencies, and Note 10 - Callaway Energy Center, under Part I, Item 1, of this report or Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K and incorporated herein by reference, include the following:


•	The complaint case filed with the MoPSC regarding the method and inputs used in calculating the performance incentive under MEEIA;


•	Ameren Illinois’ annual electric delivery service formula rate update filed with the ICC;


•	Ameren Illinois’ natural gas rate case filed with the ICC;


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


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


•	the EPA's Clean Air Act-related litigation against Ameren Missouri;


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


•	litigation associated with Ameren Missouri's liability insurance claim for the breach of the upper reservoir of its Taum Sauk pumped-storage hydroelectric energy center in December 2005; and


•	asbestos-related litigation associated with the Ameren Companies.

ITEM 1A. RISK FACTORS.

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

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

Ameren, Ameren Missouri, and Ameren Illinois did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from July 1, 2015, to September 30, 2015.

ITEM 6. EXHIBITS.

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



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

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

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

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 6, 2015