AEE- 2013.9.30-10Q

Ameren
Missouri

Ameren
Illinois

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.

AER - Ameren Energy Resources Company, LLC, an Ameren Corporation subsidiary that consists of non-rate-regulated operations, including Genco, AERG, Marketing Company and Medina Valley through March 13, 2013. Medina Valley was distributed from AER to Ameren on March 14, 2013.

Dynegy - Dynegy Inc.

FAC - Fuel adjustment clause, a fuel and purchased power 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 reviews. Net energy cost includes fuel (coal, coal transportation, natural gas for generation, and nuclear), certain fuel additives, emission allowances, purchased power costs, transmission costs and revenues, and MISO costs and revenues, net of off-system sales revenues.

FCC - Federal Communications Commission, a United States government agency.

Form 10-K - The combined Annual Report on Form 10-K for the year ended December 31, 2012, filed by Ameren, Ameren Missouri and Ameren Illinois with the SEC. With respect to Ameren only, references to Item 6, Item 7, Item 7A, Item 8 or Schedules I or II to the consolidated financial statements of the Form 10-K shall be deemed to refer to such items and schedules as they appear in Exhibits 99.1 through 99.6 to the Current Report on Form 8-K filed by Ameren with the SEC on October 17, 2013.

IPH - Illinois Power Holdings, LLC, an indirect wholly owned subsidiary of Dynegy.

Medina Valley - AmerenEnergy Medina Valley Cogen, LLC, an AER subsidiary through March 13, 2013, which owned a 40-megawatt natural gas-fired electric energy center that was sold in February 2012. This company was distributed from AER to Ameren on March 14, 2013. On October 11, 2013, Medina Valley purchased the Elgin, Gibson City, and Grand Tower gas-fired energy centers from Genco.

MISO - Midcontinent Independent System Operator, Inc., an RTO. Formerly known as Midwest Independent Transmission System Operator, Inc.

New AER - A limited liability company to be formed as a direct wholly owned subsidiary of AER. New AER will be acquired by IPH and will include substantially all of the assets and liabilities of AER, except for certain assets and liabilities retained by Ameren.

Rockland Capital - Rockland Capital, LLC as well as the special purpose entity affiliated with and formed by Rockland Capital to acquire the Elgin, Gibson City, and Grand Tower gas-fired energy centers. Rockland Capital, LLC is not an affiliate of Ameren.

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 in the Form 10-Q for the quarterly period ended March 31, 2013, 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:


•	completion of our divestiture of New AER, which is subject to Illinois Pollution Control Board approval of an Illinois MPS variance in favor of IPH on the same material terms as AER’s existing Illinois MPS variance, and completion of the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers, which is subject to FERC and other regulatory approvals;


•	Ameren's exit from the Merchant Generation business, which could result in additional impairments of long-lived assets, disposal-related losses, contingencies, reduction of existing deferred tax assets, or could have other adverse impacts on the financial condition, results of operations and liquidity of Ameren;

•

regulatory, judicial, or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the outcome of Ameren Illinois' natural gas delivery service rate case filed in 2013; the court appeals of Ameren Illinois' electric rate order issued in 2012; Ameren Missouri's request with the MoPSC for an accounting authority order relating to the deferral of certain fixed costs; Ameren Illinois' request for rehearing of FERC’s July 2012 and June 2013 orders regarding the alleged inclusion of acquisition premiums in Ameren Illinois transmission rates; 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 the 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;


•	the effects of Ameren Illinois’ expected participation, beginning in 2014, in the regulatory framework provided by the state of Illinois’ recently enacted Natural Gas Consumer, Safety and Reliability Act, which allows for the use of a rider

to recover costs of certain infrastructure investments made between rate cases;


•	the effects of, or changes to, the Illinois power procurement process;


•	the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our business at both the state and federal levels, and the implementation of deregulation;


•	changes in laws and other governmental actions, including monetary, fiscal, and tax policies, such as changes that result in our being unable to claim all or a portion of the cash tax benefits that are expected to result from the divestiture of AER;


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


•	increasing capital expenditure and operating expense requirements and our ability to recover these costs;


•	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 the ability to recover the costs for such commodities;


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


•	the level and volatility of future prices for power in the Midwest, which may have a significant effect on the financial condition of Ameren's Merchant Generation segment;


•	business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products;


•	disruptions of the capital markets, deterioration in credit metrics of the Ameren Companies, or other events that make the Ameren Companies' access to necessary capital, including short-term credit and liquidity, impossible, more difficult, or more costly;


•	our assessment of our liquidity, including liquidity concerns for Ameren's Merchant Generation business, and specifically for Genco, whose ability to borrow additional funds from external, third-party sources is restricted;


•	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 impacts of droughts, which may cause lower river levels and could limit our energy centers' ability to generate power;


•	the impact of system outages;


•	generation, transmission, and distribution asset construction, installation, performance, and cost recovery;


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


•	the extent to which Ameren Missouri prevails in its claims against insurers in connection with its Taum Sauk pumped-storage hydroelectric energy center incident;


•	the extent to which Ameren Missouri is permitted by its regulators to recover in rates the investments it made in connection with additional nuclear generation at its Callaway energy center;


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


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

•

the impact of current environmental regulations on utilities and power generating companies 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, result in an impairment of our assets, result in sales of 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, workforce reductions, future wage and employee benefits costs, including changes in discount rates and returns on benefit plan assets;


•	the inability of our counterparties and affiliates 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's and Ameren Missouri's energy centers or required to satisfy energy sales made by Ameren or Ameren Missouri;


•	legal and administrative proceedings; and


•	acts of sabotage, war, terrorism, cybersecurity attacks or intentionally disruptive acts.

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.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Operating Revenues:
Electric	$	1,507		$	1,579		$	3,823		$	3,898
Gas	131			130			693			625
Total operating revenues	1,638			1,709			4,516			4,523
Operating Expenses:
Fuel	222			194			648			550
Purchased power	128			260			400			630
Gas purchased for resale	42			40			344			304
Other operations and maintenance	383			362			1,229			1,126
Depreciation and amortization	175			161			528			496
Taxes other than income taxes	121			114			354			337
Total operating expenses	1,071			1,131			3,503			3,443
Operating Income	567			578			1,013			1,080
Other Income and Expenses:
Miscellaneous income	20			17			51			53
Miscellaneous expense	5			6			18			28
Total other income	15			11			33			25
Interest Charges	88			99			289			295
Income Before Income Taxes	494			490			757			810
Income Taxes	187			179			288			298
Income from Continuing Operations	307			311			469			512
Income (Loss) from Discontinued Operations, Net of Taxes (Note 2)	(3		)	63			(212		)	(331		)
Net Income	304			374			257			181
Less: Net Income (Loss) Attributable to Noncontrolling Interests:
Continuing Operations	2			2			5			5
Discontinued Operations	—			(2		)	—			(6		)
Net Income (Loss) Attributable to Ameren Corporation:
Continuing Operations	305			309			464			507
Discontinued Operations	(3		)	65			(212		)	(325		)
Net Income Attributable to Ameren Corporation	$	302		$	374		$	252		$	182

Earnings (Loss) per Common Share – Basic:
Continuing Operations	$	1.26		$	1.28		$	1.92		$	2.09
Discontinued Operations	(0.01		)	0.26			(0.88		)	(1.34		)
Earnings per Common Share – Basic	$	1.25		$	1.54		$	1.04		$	0.75

Earnings (Loss) per Common Share – Diluted:
Continuing Operations	$	1.25		$	1.28		$	1.91		$	2.09
Discontinued Operations	(0.01		)	0.26			(0.88		)	(1.34		)
Earnings per Common Share – Diluted	$	1.24		$	1.54		$	1.03		$	0.75

Dividends per Common Share	$	0.40		$	0.40		$	1.20		$	1.20
Average Common Shares Outstanding - Basic	242.6			242.6			242.6			242.6
Average Common Shares Outstanding - Diluted	245.1			242.9			244.4			242.9



	September 30, 2013			December 31, 2012
ASSETS
Current Assets:
Cash and cash equivalents	$	169		$	184
Accounts receivable – trade (less allowance for doubtful accounts of $20 and $17, respectively)	469			354
Unbilled revenue	226			291
Miscellaneous accounts and notes receivable	109			71
Materials and supplies	581			570
Current regulatory assets	173			247
Current accumulated deferred income taxes, net	43			170
Other current assets	108			98
Assets of discontinued operations (Note 2)	1,395			1,600
Total current assets	3,273			3,585
Property and Plant, Net	15,834			15,348
Investments and Other Assets:
Nuclear decommissioning trust fund	459			408
Goodwill	411			411
Intangible assets	19			14
Regulatory assets	1,729			1,786
Other assets	660			667
Total investments and other assets	3,278			3,286
TOTAL ASSETS	$	22,385		$	22,219
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	884		$	355
Accounts and wages payable	414			533
Taxes accrued	159			50
Interest accrued	120			89
Customer deposits	106			107
Mark-to-market derivative liabilities	65			92
Current regulatory liabilities	149			100
Other current liabilities	190			168
Liabilities of discontinued operations (Note 2)	1,141			1,166
Total current liabilities	3,228			2,660
Long-term Debt, Net	5,274			5,802
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	3,422			3,176
Accumulated deferred investment tax credits	65			70
Regulatory liabilities	1,703			1,589
Asset retirement obligations	392			375
Pension and other postretirement benefits	1,042			1,138
Other deferred credits and liabilities	534			642
Total deferred credits and other liabilities	7,158			6,990
Commitments and Contingencies (Notes 2, 3, 9, 10 and 11)
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	5,624			5,616
Retained earnings	967			1,006
Accumulated other comprehensive loss	(19		)	(8		)
Total Ameren Corporation stockholders’ equity	6,574			6,616
Noncontrolling Interests	151			151
Total equity	6,725			6,767
TOTAL LIABILITIES AND EQUITY	$	22,385		$	22,219



AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Nine Months Ended September 30,
	2013			2012
Cash Flows From Operating Activities:
Net income	$	257		$	181
Loss from discontinued operations, net of taxes	212			331
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	500			466
Amortization of nuclear fuel	46			63
Amortization of debt issuance costs and premium/discounts	18			13
Deferred income taxes and investment tax credits, net	258			249
Allowance for equity funds used during construction	(26		)	(26		)
Stock-based compensation costs	19			23
Other	14			(6		)
Changes in assets and liabilities:
Receivables	(88		)	(21		)
Materials and supplies	7			(57		)
Accounts and wages payable	(102		)	(157		)
Taxes accrued	104			95
Assets, other	20			(24		)
Liabilities, other	(24		)	61
Pension and other postretirement benefits	(34		)	16
Counterparty collateral, net	34			21
Premiums paid on long-term debt repurchases	—			(138		)
Net cash provided by operating activities - continuing operations	1,215			1,090
Net cash provided by operating activities - discontinued operations	99			222
Net cash provided by operating activities	1,314			1,312
Cash Flows From Investing Activities:
Capital expenditures	(943		)	(762		)
Nuclear fuel expenditures	(34		)	(56		)
Purchases of securities – nuclear decommissioning trust fund	(147		)	(341		)
Sales and maturities of securities – nuclear decommissioning trust fund	134			326
Other	(1		)	(6		)
Net cash used in investing activities - continuing operations	(991		)	(839		)
Net cash used in investing activities - discontinued operations	(42		)	(123		)
Net cash used in investing activities	(1,033		)	(962		)
Cash Flows From Financing Activities:
Dividends on common stock	(291		)	(284		)
Dividends paid to noncontrolling interest holders	(5		)	(5		)
Short-term debt, net	—			(143		)
Redemptions, repurchases, and maturities of long-term debt	—			(754		)
Issuances of long-term debt	—			882
Capital issuance costs	—			(7		)
Other	—			4
Net cash used in financing activities - continuing operations	(296		)	(307		)
Net cash used in financing activities - discontinued operations	—			—
Net cash used in financing activities	(296		)	(307		)
Net change in cash and cash equivalents	(15		)	43
Cash and cash equivalents at beginning of year	209			255
Cash and cash equivalents at end of period	194			298
Less cash and cash equivalents at end of period, discontinued operations	25			25
Cash and cash equivalents at end of period, continuing operations	$	169		$	273

Noncash financing activity – dividends on common stock	$	—		$	(7	)



	September 30, 2013		December 31, 2012
ASSETS
Current Assets:
Cash and cash equivalents	$	100	$	148
Advances to money pool	—		24
Accounts receivable – trade (less allowance for doubtful accounts of $7 and $5, respectively)	270		161
Accounts receivable – affiliates	9		4
Unbilled revenue	151		145
Miscellaneous accounts and notes receivable	76		48
Materials and supplies	370		397
Current regulatory assets	124		163
Other current assets	65		69
Total current assets	1,165		1,159
Property and Plant, Net	10,337		10,161
Investments and Other Assets:
Nuclear decommissioning trust fund	459		408
Intangible assets	19		14
Regulatory assets	808		852
Other assets	443		449
Total investments and other assets	1,729		1,723
TOTAL ASSETS	$	13,231	$	13,043
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	309	$	205
Accounts and wages payable	186		345
Accounts payable – affiliates	61		66
Taxes accrued	288		28
Interest accrued	67		60
Current regulatory liabilities	61		18
Other current liabilities	97		77
Total current liabilities	1,069		799
Long-term Debt, Net	3,697		3,801
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	2,472		2,443
Accumulated deferred investment tax credits	61		64
Regulatory liabilities	1,002		917
Asset retirement obligations	362		346
Pension and other postretirement benefits	423		461
Other deferred credits and liabilities	49		158
Total deferred credits and other liabilities	4,369		4,389
Commitments and Contingencies (Notes 3, 9, 10 and 11)
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	1,556		1,556
Preferred stock not subject to mandatory redemption	80		80
Retained earnings	1,949		1,907
Total stockholders’ equity	4,096		4,054
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	13,231	$	13,043



	Nine Months Ended September 30,
	2013			2012
Cash Flows From Operating Activities:
Net income	$	365		$	403
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	313			303
Amortization of nuclear fuel	46			63
FAC prudence review charge	26			—
Amortization of debt issuance costs and premium/discounts	6			5
Deferred income taxes and investment tax credits, net	62			217
Allowance for equity funds used during construction	(22		)	(23		)
Other	1			7
Changes in assets and liabilities:
Receivables	(148		)	(62		)
Materials and supplies	27			(53		)
Accounts and wages payable	(124		)	(168		)
Taxes accrued	260			59
Assets, other	59			(29		)
Liabilities, other	(78		)	22
Pension and other postretirement benefits	(12		)	17
Premiums paid on long-term debt repurchases	—			(62		)
Net cash provided by operating activities	781			699
Cash Flows From Investing Activities:
Capital expenditures	(480		)	(445		)
Nuclear fuel expenditures	(34		)	(56		)
Money pool advances, net	24			—
Purchases of securities – nuclear decommissioning trust fund	(147		)	(341		)
Sales and maturities of securities – nuclear decommissioning trust fund	134			326
Other	(3		)	(5		)
Net cash used in investing activities	(506		)	(521		)
Cash Flows From Financing Activities:
Dividends on common stock	(320		)	(300		)
Dividends on preferred stock	(3		)	(3		)
Redemptions, repurchases, and maturities of long-term debt	—			(422		)
Issuances of long-term debt	—			482
Capital issuance costs	—			(4		)
Net cash used in financing activities	(323		)	(247		)
Net change in cash and cash equivalents	(48		)	(69		)
Cash and cash equivalents at beginning of year	148			201
Cash and cash equivalents at end of period	$	100		$	132



	September 30, 2013		December 31, 2012
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	—
Accounts receivable – trade (less allowance for doubtful accounts of $13 and $12, respectively)	185		182
Accounts receivable – affiliates	28		10
Unbilled revenue	75		146
Miscellaneous accounts receivable	8		22
Materials and supplies	211		173
Current regulatory assets	49		84
Current accumulated deferred income taxes, net	35		85
Other current assets	33		47
Total current assets	625		749
Property and Plant, Net	5,369		5,052
Investments and Other Assets:
Tax receivable – Genco	37		39
Goodwill	411		411
Regulatory assets	916		934
Other assets	81		97
Total investments and other assets	1,445		1,481
TOTAL ASSETS	$	7,439	$	7,282
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	150	$	150
Borrowings from money pool	21		24
Accounts and wages payable	189		146
Accounts payable – affiliates	86		86
Taxes accrued	17		18
Customer deposits	81		85
Mark-to-market derivative liabilities	48		77
Current environmental remediation	53		37
Current regulatory liabilities	88		82
Other current liabilities	114		92
Total current liabilities	847		797
Long-term Debt, Net	1,577		1,577
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	1,095		1,025
Accumulated deferred investment tax credits	4		5
Regulatory liabilities	701		672
Pension and other postretirement benefits	376		406
Environmental remediation	194		216
Other deferred credits and liabilities	152		183
Total deferred credits and other liabilities	2,522		2,507
Commitments and Contingencies (Notes 3, 9 and 10)
Stockholders’ Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding	—		—
Other paid-in capital	1,965		1,965
Preferred stock not subject to mandatory redemption	62		62
Retained earnings	454		360
Accumulated other comprehensive income	12		14
Total stockholders’ equity	2,493		2,401
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	7,439	$	7,282



	Nine Months Ended September 30,
	2013			2012
Cash Flows From Operating Activities:
Net income	$	141		$	132
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	178			159
Amortization of debt issuance costs and premium/discounts	11			7
Deferred income taxes and investment tax credits, net	120			127
Other	(7		)	(8		)
Changes in assets and liabilities:
Receivables	66			58
Materials and supplies	(20		)	(6		)
Accounts and wages payable	31			(4		)
Taxes accrued	(2		)	(3		)
Assets, other	(33		)	(2		)
Liabilities, other	1			42
Pension and other postretirement benefits	(13		)	(8		)
Counterparty collateral, net	34			23
Premiums paid on long-term debt repurchases	—			(76		)
Net cash provided by operating activities	507			441
Cash Flows From Investing Activities:
Capital expenditures	(462		)	(309		)
Other	6			5
Net cash used in investing activities	(456		)	(304		)
Cash Flows From Financing Activities:
Dividends on common stock	(45		)	(132		)
Dividends on preferred stock	(2		)	(2		)
Money pool borrowings, net	(3		)	—
Redemptions, repurchases, and maturities on long-term debt	—			(332		)
Issuances of long-term debt	—			400
Capital issuance costs	—			(3		)
Other	—			4
Net cash used in financing activities	(50		)	(65		)
Net change in cash and cash equivalents	1			72
Cash and cash equivalents at beginning of year	—			21
Cash and cash equivalents at end of period	$	1		$	93

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, 2013

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses. 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 a rate-regulated electric and natural gas transmission and distribution business in Illinois.


•	AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes.

Ameren has various other subsidiaries responsible for activities such as the provision of shared services. Ameren also has a subsidiary, ATXI, that operates a FERC rate-regulated electric transmission business.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH, which Ameren expects will close during the fourth quarter of 2013. Immediately prior to Ameren’s entry into the transaction agreement with IPH, on March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million with respect to the sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. On October 11, 2013, Ameren received FERC approval for the divestiture of New AER to IPH and Genco’s sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. Immediately after receipt of FERC approval, Genco completed its sale of these gas-fired energy

centers to Medina Valley and received additional cash proceeds of $37.5 million. Medina Valley has entered into an agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. Ameren expects this third-party sale of these gas-fired energy centers to close by the end of 2013, subject to FERC and other regulatory approvals. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding these divestitures.

As a result of the transaction agreement with IPH and Ameren’s plan to sell its Elgin, Gibson City, and Grand Tower gas-fired energy centers, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation beginning March 14, 2013. Therefore, Ameren has segregated New AER’s and the Elgin, Gibson City, and Grand Tower gas-fired energy centers’ operating results, assets, and liabilities and presented them 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 2 - Divestiture Transactions and Discontinued Operations for additional information regarding that presentation.

The financial statements of Ameren are prepared on a consolidated basis. Ameren Missouri and Ameren Illinois have no subsidiaries, and therefore their financial statements are not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. 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.

During preparation of the 2012 annual statements of cash flows, it was identified that Ameren’s and Ameren Missouri’s 2012 interim statements of cash flows incorrectly classified certain activity from the nuclear decommissioning trust fund. Although not material, operating cash flows were overstated by $49 million for the nine months ended September 30, 2012. The overstated operating cash flows resulted in the investing cash flows being understated by the same amounts. The cash flows for the nine months ended September 30, 2012, for Ameren and Ameren Missouri have been revised in this report to correct for this error.

in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.36%, volatility of 12% to 21% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.

Intangible Assets

Ameren and Ameren Missouri classify emission allowances and renewable energy credits as intangible assets. Ameren Illinois consumes renewable energy credits as they are purchased through the IPA procurement process and expenses them immediately. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

At September 30, 2013, Ameren’s and Ameren Missouri’s intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $19 million and $19 million, respectively, at September 30, 2013. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $14 million and $14 million, respectively, at December 31, 2012.

Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. In accordance with the MoPSC's 2012 electric rate order, the majority of Ameren Missouri's amortization of intangible assets is deferred as a regulatory asset pending future recovery from customers through rates. The following table presents amortization expense based on usage of renewable energy credits and emission allowances, net of gains from sales, for Ameren, Ameren Missouri, and Ameren Illinois, during the three and nine months ended September 30, 2013, and 2012.



		Three Months			Nine Months
	2013		2012		2013		2012
Ameren Missouri	$	—	$	1	$	(a)	$	1
Ameren Illinois		2		1		9		1
Ameren	$	2	$	2	$	9	$	2


(a)	Less than $1 million.

Excise Taxes

Excise taxes levied on us are reflected on Ameren Missouri electric customer bills and on Ameren Missouri and Ameren Illinois natural gas customer bills. They 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 reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in “Taxes accrued” on the balance sheet. 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, 2013, and 2012:



	Three Months				Nine Months
	2013		2012		2013		2012
Ameren Missouri	$	49	$	46	$	120	$	111
Ameren Illinois	10		9		43		37
Ameren	$	59	$	55	$	163	$	148

Uncertain Tax Positions

The amount of unrecognized tax benefits (detriments) as of September 30, 2013, was $86 million, $27 million, and $(2) million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. Unrecognized tax benefits are included in “Other deferred credits and liabilities” on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ September 30, 2013 balance sheets. The amount of unrecognized tax benefits (detriments) as of September 30, 2013, that would impact the effective tax rate, if recognized, was $51 million, $2 million, and $(1) million for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The Ameren amount of unrecognized tax benefits that would impact the effective tax rate, if recognized, increased by $50 million primarily during the first quarter of 2013. This increase was primarily due to uncertainty related to the historical computation of Ameren’s tax basis in its stock investment in AER.

During the three months ended September 30, 2013, unrecognized tax benefits related to the deductibility of expenditures to maintain, replace, or improve steam or electric power generation property, along with casualty loss deductions for storm damage, were reduced by $113 million, $103 million, and $5 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively, with an offset to “Accumulated deferred income taxes, net.” This was the result of recent Internal Revenue Service guidance establishing new rules for the amount and timing of these deductions.

Ameren’s federal income tax returns for the years 2007 through 2011 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2012 is currently under examination.

It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the next 12 months for the years 2007 through 2011. This settlement, which is primarily related to uncertain tax positions for research tax deductions, is expected to result in a decrease in uncertain tax benefits of $23 million, $15 million, and $- million for Ameren, Ameren Missouri, and Ameren Illinois, respectively. In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe any such increases or decreases, including the decrease from the reasonably possible Internal Revenue Service Appeals Office settlement discussed above, would be material to their results of operations, financial position, or liquidity.

comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect the Ameren Companies’ results of operations, financial position, or liquidity.

In February 2013, FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. This guidance was effective for the Ameren Companies beginning in the first quarter of 2013. The implementation of this amended guidance did not affect the Ameren Companies’ results of operations, financial position, or liquidity. The only amounts reclassified out of accumulated OCI for the Ameren Companies related to pension and other postretirement plan activity and derivatives. These amounts were immaterial for the three and nine months ended September 30, 2013, and therefore no additional disclosures were required.

Disclosures about Offsetting Assets and Liabilities

In December 2011, FASB issued additional authoritative accounting guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The Ameren Companies adopted this guidance for the first quarter of 2013. The implementation of this additional guidance did not affect the Ameren Companies’ results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. See Note 7 - Derivative Financial Instruments for the required additional disclosures.

Presentation of an Unrecognized Tax Benefit

In July 2013, FASB issued additional authoritative accounting guidance to provide clarity for the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The objective of this guidance is to eliminate diversity in practice related to the presentation of certain unrecognized tax benefits. It requires entities to present an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward to the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is available under the tax law. Currently, any unrecognized tax benefit is recorded in “Other deferred credits and liabilities” on Ameren's, Ameren Missouri's,

and Ameren Illinois' balance sheets. After this guidance becomes effective, any unrecognized tax benefit will be recorded in “Accumulated deferred income taxes, net” as a reduction to the deferred tax assets for net operating loss and tax credit carryforwards on the respective balance sheets. To the extent that an unrecognized tax benefit exceeds these carryforwards, the excess would continue to be recorded in “Other deferred credits and liabilities,” on the respective balance sheets, consistent with current authoritative accounting guidance. The amended guidance will not affect the Ameren Companies' results of operations or liquidity, as this guidance is presentation-related only. This guidance will be effective for the Ameren Companies beginning in the first quarter of 2014.

NOTE 2 - DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS

Transaction Agreement with IPH

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Under the terms of the transaction agreement, AER will effect a reorganization that will, among other things, transfer substantially all of the assets and liabilities of AER, other than (i) any outstanding debt obligations of AER to Ameren or its other subsidiaries, except for certain intercompany balances discussed below, (ii) all of the issued and outstanding equity interests in Medina Valley, (iii) the assets and liabilities associated with Genco’s Meredosia, Hutsonville, Elgin, Gibson City, and Grand Tower gas-fired energy centers, (iv) the obligations relating to Ameren's single-employer pension and postretirement benefit plans, and (v) the deferred tax positions associated with Ameren's ownership of these retained assets and liabilities, to New AER. IPH will acquire all of the equity interests in New AER.

Ameren will retain the pension and postretirement benefit obligations associated with current and former employees of AER that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan. This noncurrent obligation is reflected on Ameren’s consolidated balance sheet as “Pension and other postretirement benefits.” IPH will assume the pension and other postretirement benefit obligations associated with EEI’s current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. The obligations to be assumed by IPH are estimated at $32 million at September 30, 2013. IPH will also acquire the estimated $15 million asset at September 30, 2013, relating to the overfunded status of one of EEI’s postretirement plans.

Ameren will retain Genco’s Meredosia and Hutsonville energy centers, which are idle and had an immaterial property and plant asset balance as of September 30, 2013. Ameren will also retain AROs associated with these energy centers, estimated at $27 million as of September 30, 2013. The Meredosia and Hutsonville energy centers are currently included

in continuing operations; however, Ameren is evaluating whether it would be appropriate to classify them as abandoned and discontinued coincident with closing of the transaction with IPH. All other AROs associated with AER are expected to be assumed by either New AER or the third-party buyer of the Grand Tower energy center.

Upon the transaction agreement closing, with the exception of certain agreements, such as supply obligations to Ameren Illinois, a note from New AER to Ameren relating to cash collateral that will remain outstanding at closing, and Genco money pool advances, all intercompany agreements and debt between AER and its subsidiaries, on the one hand, and Ameren and its non-AER affiliates, on the other hand, will be either retained or cancelled by Ameren, without any cost or obligation to IPH or New AER and its subsidiaries. Immediately prior to the transaction agreement closing, the cash collateral provided to New AER by Ameren through money pool borrowings will be converted to a note payable to Ameren, which will be payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced. Cash collateral postings by AER and its subsidiaries with external parties, including postings related to exchange-traded contracts, at September 30, 2013, were $27 million.

Genco's $825 million in aggregate principal amount of senior notes will remain outstanding following the closing of the transaction agreement and will continue to be solely obligations of Genco. Pursuant to the transaction agreement, in addition to the cash paid to Genco for the Elgin, Gibson City, and Grand Tower energy center sale, Ameren will cause $85 million of cash to be retained at New AER.

As a condition to the transaction agreement, Genco exercised the amended put option agreement for the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. In October 2013, immediately after receipt of FERC approval, Genco completed the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley.

Completion of the divestiture of New AER to IPH requires FERC and FCC approvals. In October 2013, FERC issued an order approving the divestiture of New AER. The FCC approval was received in August 2013. Separately, as a condition to IPH’s obligation to complete the New AER transaction, the Illinois Pollution Control Board must approve the transfer to IPH of, or otherwise approve a variance in favor of IPH on the same material terms as, AER’s variance of the Illinois MPS. In May 2013, AER and IPH filed a transfer request with the Illinois Pollution Control Board, which was subsequently denied by the board on procedural grounds. On July 22, 2013, IPH, AER, and Medina Valley, as current and future owners of the coal-fired energy centers, filed a request for a variance with the Illinois Pollution Control Board seeking materially the same relief as the existing AER variance. The Illinois Pollution Control Board has until late November 2013 to issue a decision. See Note 10 - Commitments and Contingencies for additional information. Ameren’s and IPH’s obligation to complete the transaction is also subject to other customary closing conditions, including the

material accuracy of each company’s representations and warranties and the compliance, in all material respects, with each company’s covenants. The transaction agreement contains customary representations and warranties of Ameren and IPH, including representations and warranties of Ameren with respect to the business being sold. The transaction agreement also contains customary covenants of Ameren and IPH, including the covenant of Ameren that AER will be operated in the ordinary course prior to the closing.

Ameren expects the closing of the New AER divestiture to IPH will occur in the fourth quarter of 2013. If the closing does not occur on or before March 14, 2014, either party may elect to terminate the transaction agreement if the inability to close the transaction by such date is not the result of the failure of the terminating company to fulfill any of its obligations under the transaction agreement. The transaction agreement with IPH also provides for a $25 million cash termination fee if either Ameren or IPH breach any of their representations, warranties, covenants or obligations in a manner that would result in the other party having the right to terminate the transaction agreement, or if Ameren or IPH fails to complete the transaction within three business days of the scheduled closing date, subject to certain exceptions.

Amended Put Option Agreement, Asset Purchase Agreement and Guaranty

Prior to entry into the transaction agreement with IPH as discussed above, (i) the original put option agreement between Genco and AERG was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley and (ii) Genco exercised its option under the amended put option agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. As a result, on March 14, 2013, Genco received an initial payment of $100 million in accordance with the terms of the amended put option agreement. Genco advanced the initial payment amount it received into the non-state-regulated subsidiary money pool. In connection with the amended put option agreement, Ameren's guaranty, dated March 28, 2012, was modified to replace all references to AERG with references to Medina Valley.

Pursuant to the amended put option agreement, Genco and Medina Valley entered into an asset purchase agreement, dated March 14, 2013. The asset purchase agreement provided that Genco would receive an additional payment upon closing of the asset purchase agreement to the extent the average fair market value for the Elgin, Gibson City, and Grand Tower gas-fired energy centers, as determined based on three independent appraisals, exceeded the $100 million initial payment Genco received from Medina Valley. Genco and Medina Valley engaged three independent appraisers to conduct fair market valuations of the Elgin, Gibson City, and Grand Tower gas-fired energy centers. The average fair market value pursuant to such appraisals for the Elgin, Gibson City, and Grand Tower gas-fired energy centers was $137.5 million, which was greater than the original fair value estimate of $133 million. Therefore, after receipt of FERC approval and upon closing of the asset purchase

agreement in October 2013, Genco received an additional payment of $37.5 million from Medina Valley. Genco advanced the additional $37.5 million it received into the non-state-regulated subsidiary money pool.

The transaction agreement with IPH provides that if the Elgin, Gibson City, and Grand Tower gas-fired energy centers are subsequently sold to a third-party and Medina Valley receives proceeds within two years of the closing of the New AER divestiture, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the amounts previously paid to Genco, which totaled $137.5 million.

Medina Valley has entered into an agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. This agreement requires a portion of the purchase price to be held in escrow until the two year anniversary of the closing of the sale to fund certain indemnity obligations, if any, of Medina Valley. Ameren expects the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital to close by the end of 2013, subject to receipt of FERC and other regulatory approvals. If this sale is completed, Medina Valley could pay Genco after-tax net proceeds of up to an additional $15 million based on the maximum escrow amount that could ultimately be released, projected working capital adjustments, and projected transaction expenses.

In August 2013, the Illinois Municipal Electric Agency, which is a wholesale customer of Marketing Company, filed a lawsuit in

the United States District Court for the Central District of Illinois against Marketing Company alleging that the removal of certain assets that were related to the amended put option agreement from the parties’ contract schedules without the customer’s consent constituted a breach of contract. In addition, the lawsuit alleges that Genco and AERG failed to recognize certain asset impairments that the Illinois Municipal Electric Agency alleges have occurred and which the Illinois Municipal Electric Agency claims would, if recognized, reduce the billings to the Illinois Municipal Electric Agency. The lawsuit also makes certain other claims that the proposed divestiture would result in a breach of the parties’ contract. Marketing Company believes its defenses to these allegations are meritorious and will defend itself vigorously.

Discontinued Operations Presentation

As of March 14, 2013, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation and, therefore, were classified separately in Ameren’s consolidated financial statements as discontinued operations for all periods presented in this report. Ameren concluded that New AER and collectively the Elgin, Gibson City, and Grand Tower gas-fired energy centers are two separate disposal groups. Both disposal groups have been aggregated in the disclosures below. Each disposal group was measured at fair value on a nonrecurring basis with inputs that are classified as Level 3 within the fair value hierarchy.

As the New AER disposal group continued to meet the discontinued operations criteria at September 30, 2013, Ameren evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value of the disposal group, less cost to sell. The fair value was based on the terms of Ameren’s agreement to divest New AER to IPH. Ameren will receive no cash proceeds from IPH for the divestiture of New AER. Ameren recorded a cumulative pretax charge to earnings of $175 million for the nine months ended September 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. Ameren recorded a pretax

charge to earnings of $7 million for the three months ended September 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. The pretax charge to earnings increased during the three months ended September 30, 2013, as the disposal group’s carrying value increased, primarily as a result of contributions made to EEI’s pension plan and derivative market value gains. The impairment loss was recorded in “Operating expenses” within the components of the discontinued operations statement of income with a corresponding reduction in “Property and Plant, net” within the components of the discontinued operations balance sheet.

Ameren estimated the impairment loss of the disposal group based on the estimated fair value pursuant to the terms of the transaction agreement with IPH, using information currently available, and assuming an expected fourth quarter 2013 closing. Actual operating results, derivative market values, capital expenditures and other items will impact the ultimate loss recognized to reduce the carrying value of the New AER disposal group to its actual fair value less cost to sell, which will be recorded in discontinued operations after all of the information becomes available. In addition, any curtailment gain related to Ameren's pension and postretirement plans will be recorded when the related employees terminate employment with Ameren. The ultimate impairment loss may differ materially from the estimated loss recorded as of September 30, 2013.

Ameren adjusted accumulated deferred income taxes on its balance sheet to reflect the excess of tax basis over financial reporting basis of its stock investment in AER, during the three months ended March 31, 2013, when it became apparent that the temporary difference would reverse. This change in basis resulted in a discontinued operations deferred tax expense of $96 million, which was partially offset by the expected tax benefits of $72 million related to the pretax loss from discontinued operations including the impairment charge, during the nine months ended September 30, 2013. During the third quarter of 2013, Ameren recorded tax benefits of $3 million related to the incremental pretax loss from discontinued operations recorded during the third quarter of 2013. In addition, Ameren recorded a $1 million reduction in discontinued operations deferred tax expense during the third quarter of 2013 to reflect changes in the estimates of the excess of tax basis over financial reporting basis of Ameren’s stock investment in AER. The final tax basis of the AER disposal group and the related tax benefit resulting from the transaction agreement with IPH are dependent upon taxable losses utilized by the disposal group through the closing and the resolution of tax matters under audit, including the adoption of recently issued guidance from the Internal Revenue Service related to tangible property repairs and other matters. As a result, tax expense and benefits realized in discontinued operations may differ materially from those recorded as of September 30, 2013.

As the Elgin, Gibson City, and Grand Tower gas-fired energy center disposal group continued to meet the discontinued operations criteria at September 30, 2013, Ameren evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value of the disposal group, less cost to sell. The fair value was based on the appraised value of these three gas-fired energy centers. In December 2012, Ameren recorded a noncash long-lived asset impairment charge to reduce the carrying value of AER’s energy centers, including the Elgin, Gibson City, and Grand Tower gas-fired energy centers, to their estimated fair values under the accounting guidance for held and used assets. The December 2012 held and used asset impairment charge reduced these energy centers’ disposal group carrying value to their estimated fair value of $133 million. Ameren will not recognize a gain from the third party sale to Rockland Capital for any value in excess of the $133 million carrying value of this disposal group since any excess amount that Medina Valley may receive, net of taxes and other expenses, over the carrying value, will ultimately be paid to Genco pursuant to the transaction agreement with IPH. Ameren does not expect to have significant continuing involvement or material cash flows with the Elgin, Gibson City, and Grand Tower gas-fired energy centers after their sale.

Effective with its conclusion that the New AER disposal group and the Elgin, Gibson City, and Grand Tower gas-fired energy centers’ disposal group each met the criteria for held for sale presentation, Ameren suspended recording depreciation on these assets in March 2013.

Interest on Genco’s senior notes, which will continue to be solely obligations of Genco following the closing of the transaction agreement with IPH, are included in the “Interest charges” component within the discontinued operations line item in the statement of income. Ameren did not allocate corporate interest to the disposal groups. Additionally, general corporate overhead expenses originally allocated to the disposal groups were classified as expenses of continuing operations.

Ameren will have continuing transactions with New AER after the divestiture is complete. Ameren Illinois has power supply agreements with Marketing Company, which are a result of the power procurement process in Illinois administered by the IPA as required by the Illinois Public Utilities Act. Ameren Illinois will continue to purchase power and purchase trade receivables as required by Illinois law, and Ameren will reflect these items as continuing operations after the divestiture occurs. Ameren Illinois and ATXI currently sell, and will continue to sell, transmission services to Marketing Company after the divestiture of New AER is completed. Also, upon the divestiture of New AER, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER for all transactions entered into prior to the closing of such divestiture for up to 24 months after the closing. 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 will be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH’s indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions). Immediately prior to the transaction agreement closing, the cash collateral provided to New AER by Ameren through money pool borrowings will be converted to a note payable to Ameren which will be payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced. Also, within 120

days after closing, a working capital adjustment will be finalized, which may result in a cash payment from Ameren to New AER. Ameren has determined that the continuing cash flows generated by these arrangements are not significant and, accordingly, are not deemed direct cash flows of the divested business. Additionally, these arrangements do not provide Ameren the ability to significantly influence the operating results of New AER after the divestiture is complete. See Note 9 - Related Party Transactions for additional information regarding existing transactions between Ameren and New AER.

For a period of up to 12 months following the closing, Ameren will provide certain transitional services to IPH. Such services will be provided at no charge for 90 days, subject to a $5 million limit; thereafter, services will be provided at cost, except for certain services that may be applied to the $5 million limit to the extent such limit has not been reached by the end of the 90 day period. The transitional services may be provided for six months after the closing and can be extended by IPH on a month-to-month basis for up to an additional six months.

See Note 10 - Commitments and Contingencies for information regarding amendments to the plant transfer agreements between both Genco and Ameren Illinois and AERG and Ameren Illinois as well as other AER related matters.

Genco Indenture Provisions

Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these ratios for the 12 months ended and as of September 30, 2013:



	Required Ratio	Actual Ratio
Interest coverage ratio- restricted payment ^(a)	≥1.75	1.05
Interest coverage ratio- additional indebtedness ^(b)	≥2.50	1.05
Debt-to-capital ratio- additional indebtedness ^(b)	≤60%	51	%

(a)

As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.

(b)

Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Genco’s debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness.

As shown in the table above, under the provisions of Genco’s indenture, Genco may not borrow additional funds from external, third-party sources if its interest coverage ratio is less than 2.5 or its debt-to-capital ratio is greater than 60%. Beginning in the first quarter of 2013, Genco’s interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and Genco expects the ratio to remain less than this minimum level through at least 2015. As a result, Genco’s ability to borrow additional funds from external third-party sources is restricted. Genco’s indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren’s control. If a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time. As stated above, the transaction agreement requires Ameren to operate New AER, including Genco, in the ordinary course prior to the closing.

Illinois Sales and Use Tax Exemptions and Credits

Beginning in the second quarter of 2010 through 2011, Genco, including EEI, and AERG claimed Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. During the second quarter of 2013, Ameren and the Illinois Department of Revenue resolved a tax dispute relating to these sales and use tax exemptions and credits for all open periods related to this issue with an aggregate

payment of $7 million by Genco, including EEI, and AERG to the Illinois Department of Revenue. This charge was recorded within “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income for the nine months ended September 30, 2013.

NOTE 3 - 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

FAC Prudence Reviews

In April 2011, the MoPSC issued an order with respect to its review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda's load caused by a severe ice storm in January 2009. In May 2012, upon appeal by Ameren Missouri, the Cole County Circuit Court reversed the MoPSC's April 2011 order. In June 2012, the MoPSC and a group of large industrial customers filed an appeal of the Cole County Circuit Court's ruling to the Missouri Court of Appeals, Western District. In May 2013, the Missouri Court of Appeals upheld the MoPSC’s April 2011 order and reversed the Cole County Circuit Court’s May 2012 decision. Ameren Missouri determined that it would not appeal the Missouri Court of Appeals’ decision.

Ameren Missouri’s FAC calculation for the period from October 1, 2009, to May 31, 2011, excluded all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda’s load caused by a severe ice storm in January 2009, similar to the FAC calculation for the period from March 1, 2009, to September 30, 2009. As a result of the Missouri Court of Appeal’s May 2013 decision on the MoPSC’s April 2011 order, Ameren Missouri recorded a pretax charge to earnings of $23 million, including $1 million for interest, in the second quarter of 2013 for its estimated obligation to refund to Ameren Missouri’s electric customers the earnings associated with these sales previously recognized by Ameren Missouri for the period from October 1, 2009, to May 31, 2011. Ameren Missouri recorded the charge to “Operating Revenues - Electric” and the related interest to “Interest Charges” with a corresponding offset to “Current regulatory liabilities.” On July 31, 2013, the MoPSC issued an order calculating the refund of these earnings to be $26 million, including $1 million of interest. As a result, during third quarter of 2013, Ameren Missouri recorded an additional pretax charge to earnings of $3 million. Ameren Missouri expects to begin making customer refunds in the first quarter of 2014. No

similar revenues were excluded from FAC calculations after May 2011.

Separately, in July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren Missouri to defer, as a regulatory asset, fixed costs totaling $36 million that were not recovered from Noranda as a result of the loss of load caused by the severe 2009 ice storm for potential recovery in a future electric rate case. Ameren Missouri expects the MoPSC to issue an order related to this request in the fourth quarter of 2013.

2012 Electric Rate Order

In December 2012, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $260 million. In January 2013, Ameren Missouri appealed the order with respect to the amount of property taxes included in the order to the Missouri Court of Appeals, Western District. In February 2013, the MoOPC, MIEC, and other parties filed separate appeals to the Missouri Court of Appeals, Western District, relating to the 2012 electric rate order’s treatment of transmission costs in the FAC. In July 2013, Ameren Missouri withdrew its appeal related to the 2012 electric rate order. In October 2013, the Missouri Court of Appeals, Western District, issued its opinion affirming the MoPSC’s December 2012 rate order. In October 2013, the MoOPC, MIEC, and other parties filed a rehearing request with the Missouri Court of Appeals, Western District.

Illinois

IEIMA

Under the provisions of the IEIMA, Ameren Illinois’ electric delivery service rates effective in 2013 are subject to an annual revenue requirement reconciliation to its actual 2013 costs. The 2013 revenue requirement reconciliation will be filed with the ICC in 2014. The approved annual revenue requirement reconciliation adjustment will be reflected in customer rates beginning in January 2015. Throughout the 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 in effect 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 costs incurred. As of September 30, 2013, Ameren Illinois recorded a $59 million regulatory asset to reflect the year-to-date portion of its expected 2013 revenue requirement reconciliation adjustment. As of September 30, 2013 and December 31, 2012, Ameren Illinois recorded a regulatory liability of $59 million and $55 million, respectively, to reflect its expected 2012 revenue requirement reconciliation adjustment, with interest, which will be refunded to customers in 2014, pending ICC approval as discussed below.

In May 2013, Illinois enacted into law certain amendments to the IEIMA that modify its implementation. The law clarified that the IEIMA requires that the year-end rate base be used to calculate the revenue requirement reconciliation and that the

interest applied to the revenue requirement reconciliation and return on equity collar adjustments be equal to a company’s weighted-average return calculated under the formula rate.

In September 2012, the ICC issued an order in Ameren Illinois’ initial filing under the IEIMA’s performance-based formula rate framework, which Ameren Illinois appealed to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2014. In December 2012, the ICC issued an order in Ameren Illinois’ update filing approving an Ameren Illinois electric delivery service revenue requirement of $765 million, based on 2011 recoverable costs and expected net plant additions for 2012. The delivery service rates became effective on January 1, 2013, and will remain effective through the end of 2013. These rates are subject to a reconciliation to actual 2013 costs, which will be filed with the ICC in 2014. In January 2013, Ameren Illinois filed an appeal of the ICC's update filing order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2014. Many of the issues that were the subject of Ameren Illinois’ appeals of the September 2012 order and the December 2012 order were resolved with the enactment of the May 2013 amendments to the IEIMA referred to above; however, disputes regarding the treatment of deferred taxes and vacation obligations as well as the calculation of Ameren Illinois’ capital structure remain. If the appellate court rules in favor of Ameren Illinois’ positions on these disputed items, the electric delivery service revenue requirement included in the December 2012 order would have increased by $11 million. Ameren Illinois anticipates that any change resulting from the appellate court decision would be incorporated into the IEIMA formula rate process, including the revenue requirement reconciliation, in the year the decision is issued.

In April 2013, Ameren Illinois filed its annual electric delivery service formula rate update with the ICC based on 2012 recoverable costs and expected net plant additions for 2013. In July 2013, the update filing was revised based on the enactment of the May 2013 amendments to the IEIMA referred to above. Pending ICC approval, Ameren Illinois’ revised update filing would result in an aggregate $22 million decrease in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2014. The revised update filing includes a proposed refund to customers of the 2012 revenue requirement reconciliation of $55 million, which includes an estimate for interest through the end of 2014. Ameren Illinois’ balance sheet as of September 30, 2013, includes a $59 million regulatory liability relating to this 2012 revenue requirement reconciliation, which will continue to accrue interest through 2014 and is expected to increase to $63 million with interest accrued through 2014. In the revised update filing, the proposed refund is partially offset by an annual revenue requirement increase of $33 million primarily due to increased recoverable costs over 2011 levels. Ameren Illinois’ filing reflects an electric delivery service revenue requirement of $798 million, before consideration of the 2012 revenue requirement reconciliation refund. In October 2013, the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ revised update filing. The ICC staff recommended an aggregate $42 million decrease in Ameren Illinois’ electric delivery service revenue requirement. The

calculation includes a refund to customers of the 2012 revenue requirement reconciliation of $66 million, which includes an estimate for interest through the end of 2014. However, this refund is partially offset by an annual revenue requirement increase of $24 million primarily due to increased recoverable costs over 2011 levels. The ICC staff’s filing reflects an electric delivery service revenue requirement of $789 million, before consideration of the 2012 revenue requirement reconciliation refund. An ICC decision with respect to the update filing is required in December 2013 and will establish rates for all of 2014. In December 2013, Ameren Illinois will record an adjustment to its regulatory liability for its 2012 revenue requirement reconciliation refund based on the ICC’s order.

2013 Natural Gas Delivery Service Rate Case

In January 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service. The current request, as revised in August 2013, seeks to increase annual revenues for natural gas delivery service by $47 million. The revised natural gas rate increase request was based on a 10.4% return on equity, a capital structure composed of 51.8% common equity, and a rate base of $1.1 billion. In an attempt to reduce regulatory lag, Ameren Illinois is using a future test year of 2014 in this proceeding.

Also in its filing, Ameren Illinois is seeking recovery of capital costs to enable residential customers the option to choose their natural gas commodity supplier, although that option currently does not exist for these customers.

In September 2013, the ICC staff responded to Ameren Illinois' revised request and recommended an increase in revenues for natural gas delivery service of $28 million, based on an 8.8% return on equity, a capital structure composed of 50.4% common equity, and a rate base of $1.1 billion.

A decision by the ICC in this proceeding is required in December 2013. Ameren Illinois cannot predict the level of any natural gas delivery service rate changes the ICC may approve or whether any rate changes that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and earn a reasonable return on its investments when the rate changes go into effect.

Natural Gas Consumer, Safety and Reliability Act

In July 2013, Illinois enacted a law called the Natural Gas Consumer, Safety and Reliability Act that enables Illinois natural gas utilities to accelerate modernization of the state’s natural gas infrastructure and provide additional ICC oversight of natural gas utility performance. Utilities that participate may implement rate surcharges for certain infrastructure investments made between rate cases. The legislation allows natural gas utilities the option to file, and requires the ICC to approve, a rate rider mechanism to provide for recovery of costs associated with certain categories of investment to improve the safety and reliability of the state’s natural gas infrastructure. The legislation also requires natural gas utilities that choose to participate in this regulatory framework to file annual plans with the ICC and report on progress in

achieving performance improvements. Ameren Illinois expects to begin participation in this regulatory framework in 2014.

ATXI Transmission Project

ATXI’s Illinois Rivers project is a MISO-approved project to build a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri at an estimated cost of $1.1 billion. In 2012, ATXI made a filing with the ICC requesting a certificate of public convenience and necessity, and project approval. In August 2013, the ICC granted a certificate of public convenience and necessity and approved seven of a total of nine sections of the route and three of the proposed nine substations for the Illinois Rivers project. The ICC order indicated the project is necessary to address transmission and reliability needs in an efficient and equitable manner and that the project will benefit the development of a competitive electricity market. The order also indicated that ATXI is capable of constructing and managing the project and capable of financing it. In October 2013, the ICC granted ATXI’s request for rehearing to consider additional evidence regarding the two segments of the route and six substations that were not approved, as well as the requests for rehearing of certain other parties regarding two of the approved segments of the route. An order on rehearing is expected in March 2014.

Federal

2011 Wholesale Distribution Rate Case

In January 2011, Ameren Illinois filed a request with FERC to increase its annual revenues for electric delivery service for its wholesale customers. These wholesale distribution revenues are treated as a deduction from Ameren Illinois’ revenue requirement in retail rate filings with the ICC. In March 2011, FERC issued an order authorizing the proposed rates to take effect, subject to refund when the final rates are determined. Ameren Illinois has reached an agreement with four of its nine wholesale customers. The impasse with the remaining five wholesale customers has resulted in FERC litigation. In November 2012, a FERC administrative law judge issued an initial decision, which is now pending before FERC. The timing of a FERC decision is uncertain. Based on the administrative law judge's initial decision, Ameren and Ameren Illinois each has included on its balance sheet in “Current regulatory liabilities” an estimate of $12 million and $8 million as of September 30, 2013, and December 31, 2012, respectively, for the refund due to wholesale customers relating to billings for the period from March 2011 through September 2013.

Ameren Illinois Electric Transmission Rate Refund

In July 2012, FERC issued an order with respect to Ameren Illinois' accounting for the Ameren Illinois Merger. As part of this order, FERC concluded that Ameren Illinois improperly included acquisition premiums, particularly goodwill, in determining its common equity used in its electric transmission formula rate, thereby inappropriately recovering a higher return on rate base from its electric transmission customers. The order required Ameren Illinois to make refunds to customers for such improperly

included amounts. In August 2012, Ameren Illinois filed a request for rehearing of this order. It is unknown when FERC will rule on Ameren's rehearing request, as it is under no deadline to do so. Ameren Illinois submitted a refund report in November 2012 and concluded that no refund was warranted. Several wholesale customers filed a protest with FERC regarding Ameren's conclusion that no refund is warranted.

In June 2013, FERC issued an order that rejected Ameren Illinois’ November 2012 refund report and provided guidance as to the filing of a new refund report. In July 2013, Ameren Illinois filed a revised refund report based on the guidance provided in the June 2013 order, and also filed a request for rehearing of that order. Ameren Illinois’ July 2013 refund report again concluded that no refund was warranted. Ameren Illinois estimates the maximum pretax charge to earnings for this contingency would be between $10 million and $15 million, before interest charges. If Ameren Illinois were to determine that a refund to its electric transmission customers is probable, a charge to earnings would be recorded for the refund in the period in which that determination was made.

Combined Construction and Operating License

In 2008, Ameren Missouri filed an application with the NRC for a COL for a new nuclear unit at Ameren Missouri's existing Callaway County, Missouri, energy center site. In 2009, Ameren Missouri suspended its efforts to build a new nuclear unit at its existing Missouri nuclear energy center site, and the NRC suspended review of the COL application.

In March 2012, the DOE announced the availability of investment funds for the design, engineering, manufacturing, and sale of American-made small modular nuclear reactors. In April 2012, Ameren Missouri entered into an agreement with Westinghouse to exclusively support Westinghouse's application for the first installment of DOE's small modular nuclear reactor investment funds. The DOE investment funding is intended to support engineering and design certifications and a COL for up to two small modular reactor designs over five years. In November 2012, the DOE awarded the first installment of investment funds for only one small modular reactor design, which was not the Westinghouse design, but also stated that a second installment of investment funds would be awarded during 2013. Westinghouse continues to seek funds from the DOE’s first installment of investment funds.

Westinghouse submitted an application to the DOE in June 2013 for the second installment of investment funds. If Westinghouse is awarded DOE's small modular reactor investment funds in this second installment round of funding, Ameren Missouri may pursue a COL from the NRC for a Westinghouse small modular reactor or multiple reactors at its Callaway energy center site. A COL is issued by the NRC to permit construction and operation of a nuclear energy center at a specific site in accordance with established laws and regulations. Obtaining a COL from the NRC would not obligate Ameren Missouri to build a small modular reactor at the Callaway site; however, it would preserve the option to move forward in a timely

fashion should conditions be right to build a small modular reactor in the future. A COL is valid for at least 40 years.

Ameren Missouri estimates the total cost to obtain the small modular reactor COL will be in the range of $80 million to $100 million. As of September 30, 2013, Ameren Missouri has capitalized investments for the development of a new nuclear energy center of $69 million. Ameren Missouri expects its incremental investment to obtain the small modular reactor COL to be minimal. As discussed above, the DOE investment funds could help support the completion of a COL application. If the DOE does not select Westinghouse's applications for small modular reactor investment funds, Ameren Missouri is not obligated to pursue a COL for the Westinghouse small modular reactor design and may terminate its agreement with Westinghouse regarding the first installment of DOE investment funds.

All of Ameren Missouri's costs incurred to license additional nuclear generation at the Callaway site will remain capitalized while management pursues options to maximize the value of its investment. If efforts are permanently abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination is made.

NOTE 4 - SHORT-TERM DEBT AND LIQUIDITY

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

The 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement were not utilized for borrowings during the nine months ended September 30, 2013. As of September 30, 2013, based on letters of credit issued under the 2012 Credit Agreements, as well as commercial paper outstanding, the aggregate amount of credit capacity available to Ameren (parent), Ameren Missouri and Ameren Illinois, collectively, at September 30, 2013, was $2.09 billion.

Commercial Paper

Ameren did not have any commercial paper outstanding at September 30, 2013, or December 31, 2012. The average daily commercial paper balances outstanding during the nine months ended September 30, 2013, and 2012, were $26 million and $58 million, respectively. The weighted-average interest rates during the nine months ended September 30, 2013, and 2012, were 0.52% and 0.93%, respectively. The peak short-term commercial paper balances outstanding during the nine months ended September 30, 2013, and 2012, were $92 million and $229 million, respectively. The peak interest rates during the nine months ended September 30, 2013, and 2012, were 0.85% and 1.25%, respectively. Ameren Missouri and Ameren Illinois did not utilize their commercial paper programs during the nine months ended September 30, 2013, and 2012.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants within 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 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, 2013, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2012 Credit Agreements, were 51%, 48% and 42%, 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, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1, to be calculated quarterly, as of the end of the most recent four fiscal quarters then ending, in accordance with the 2012 Illinois Credit Agreement. Ameren’s ratio as of September 30, 2013, was 5.1 to 1.0. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2012 Credit Agreement. Ameren’s ratios, as discussed above, include both continuing and discontinued operations for the purposes of these calculations.

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. Management believes that the Ameren Companies were in compliance with the provisions and covenants of their credit agreements at September 30, 2013.

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. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.

Utility

Ameren Missouri, Ameren Illinois and Ameren Services may participate in the utility money pool as both lenders and borrowers. Ameren (parent) and AERG may participate in the utility money pool only as lenders. Internal funds are surplus

funds 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. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement 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 rates for borrowing under the utility money pool for the three and nine months ended September 30, 2013, were 0.05% and 0.08%, respectively (2012 - 0.14% and 0.13%, respectively).

Non-state-regulated Subsidiaries

Ameren (parent), Ameren Services, AER, Genco, AERG, Marketing Company, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company and applicable regulatory short-term borrowing authorizations, to access funding from the 2012 Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. AER, Genco, AERG and Marketing Company may participate in the non-state-regulated money pool through the closing of the divestiture transaction as detailed in Note 2 - Divestiture Transactions and Discontinued Operations. All participants may borrow from or lend to the non-state-regulated money pool, except for Ameren Services, which may participate only as a borrower. The total amount available to the pool participants from the non-state-regulated subsidiary 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 non-state-regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement 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 non-state-regulated subsidiary money pool. The average interest rates for borrowing under the non-state-regulated subsidiary money pool for the three and nine months ended September 30, 2013, were 0.36% and 0.29%, respectively (2012 - 0.52% and 0.64%, respectively).

See Note 9 - 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, 2013, and 2012.

Ameren’s indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 2012 Credit Agreements, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period.

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.” 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 net income and 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 FERC to maintain a minimum 30% ratio of common stock equity to total capitalization after the Ameren Illinois Merger and AERG distribution. As of September 30, 2013, Ameren Illinois’ ratio of common stock equity to total capitalization was 58%.

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

Off-Balance-Sheet Arrangements

At September 30, 2013, 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.

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 8 - Fair Value Measurements for our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.

If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income or the statement of income and comprehensive income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income or the statement of income and

comprehensive income. Currently, we have not elected cash flow hedge accounting for any of our derivative contracts.

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. Ameren Missouri and Ameren Illinois believe derivative gains and losses 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.

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for, or we do not choose to elect, the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income or the statement of income and comprehensive income in the period in which the change occurs.

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

The following table presents the carrying value and balance sheet location of all derivative instruments as of September 30, 2013, and December 31, 2012:



	Balance Sheet Location		Ameren		Ameren Missouri		Ameren Illinois
2013
Derivative assets not designated as hedging instruments^(a)
Commodity contracts:
Fuel oils	Other current assets	$	6	$	6	$	—
	Other assets		2		2		—
Natural gas	Other current assets		1		1		—
Power	Other current assets		30		30		—
	Other assets		1		1		—
Uranium	Other current assets		1		1		—
	Total assets	$	41	$	41	$	—
Derivative liabilities not designated as hedging instruments^(a)
Commodity contracts:
Fuel oils	MTM derivative liabilities	$	3	$	(b)	$	—
	Other current liabilities		—		3		—
	Other deferred credits and liabilities		1		1		—
Natural gas	MTM derivative liabilities		45		(b)		38
	Other current liabilities		—		7		—
	Other deferred credits and liabilities		30		6		24
Power	MTM derivative liabilities		13		(b)		10
	Other current liabilities		—		3		—
	Other deferred credits and liabilities		84		—		84
Uranium	MTM derivative liabilities		4		(b)		—
	Other current liabilities		—		4		—
	Other deferred credits and liabilities		2		2		—
	Total liabilities	$	182	$	26	$	156
2012
Derivative assets not designated as hedging instruments^(a)
Commodity contracts:
Fuel oils	Other current assets	$	8	$	8	$	—
	Other assets		4		4		—
Natural gas	Other current assets		1		—		1
	Other assets		1		1		—
Power	Other current assets		14		14		—
	Other assets		1		1		—
	Total assets	$	29	$	28	$	1
Derivative liabilities not designated as hedging instruments^(a)
Commodity contracts:
Fuel oils	MTM derivative liabilities	$	2	$	(b)	$	—
	Other current liabilities		—		2		—
	Other deferred credits and liabilities		2		2		—
Natural gas	MTM derivative liabilities		64		(b)		56
	Other current liabilities		—		8		—
	Other deferred credits and liabilities		45		7		38
Power	MTM derivative liabilities		25		(b)		21
	Other current liabilities		—		4		—
	Other deferred credits and liabilities		90		—		90
Uranium	MTM derivative liabilities		1		(b)		—
	Other current liabilities		—		1		—
	Other deferred credits and liabilities		1		1		—
	Total liabilities	$	230	$	25	$	205

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, 2013, and December 31, 2012, 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 trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on September 30, 2013, or December 31, 2012, respectively, 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)
2013
Ameren Missouri	$	69	$	1	$	63
Ameren Illinois	101		24		70
Ameren	$	170	$	25	$	133
2012
Ameren Missouri	$	78	$	3	$	71
Ameren Illinois	148		58		84
Ameren	$	226	$	61	$	155

NOTE 8 - 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 the following three hierarchy levels:

Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives and assets, including cash and cash equivalents and listed equity securities, such as those held in Ameren Missouri’s Nuclear Decommissioning Trust Fund.

The market approach is used to measure the fair value of equity securities held in Ameren Missouri’s Nuclear Decommissioning Trust Fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants and the trustee and investment managers. The S&P 500 index is comprised of stocks of large capitalization companies.

Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets

and liabilities include certain assets held in Ameren Missouri’s Nuclear Decommissioning Trust Fund, including corporate bonds and other fixed-income securities, United States treasury and agency securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.

Fixed income securities are valued using prices from independent, industry recognized data vendors who provide values that are either exchange based or matrix based. The fair value measurements of fixed income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market-corroborated pricing, and inputs such as yield curves and indices. Level 2 fixed income securities in the Nuclear Decommissioning Trust Fund are comprised primarily of corporate bonds, asset-backed securities and United States agency bonds.

Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint. Natural gas derivative contracts are valued based upon exchange closing prices without significant unobservable adjustments. Power derivative contracts are valued based upon the use of multiple forward prices provided by third parties. The



		Fair Value								Weighted
		Assets		Liabilities			Valuation Technique	Unobservable Input	Range	Average
Level 3 Derivative asset and liability - commodity contracts^(a):
Ameren	Fuel oils	$	7	$	(4	)	Option model	Volatilities(%)^(b)	9 - 20	17
							Discounted cash flow	Counterparty credit risk(%)^(c)(d)	.26 - 3	2
	Natural gas	1		(1		)	Option model	Volatilities(%)^(b)	5 - 29	24
								Nodal basis($/mmbtu)^(c)	(0.40) - (0.20)	(0.40)
							Discounted cash flow	Nodal basis($/mmbtu)^(c)	(0.10)	(e)
								Counterparty credit risk(%)^(c)(d)	0.64 - 0.83	0.77
								Ameren credit risk(%)^(c)(d)	2 - 3	2
	Power^(f)	29		(95		)	Discounted cash flow	Average forward peak and off-peak power pricing - forwards/swaps($/MWh)^(c)	27 - 43	30
								Estimated auction price for FTRs($/MW)^(b)	(103) - 1790	660
								Nodal basis($/MWh)^(c)	(5) - (1)	(3)
								Counterparty credit risk(%)^(c)(d)	0.22 - 3	0.73
								Ameren credit risk(%)^(c)(d)	3	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)^(b)	4 - 7	5
								Escalation rate(%)^(b)(g)	4 - 5	4
							Contract price allocation	Estimated renewable energy credit costs($/credit)^(b)	5 - 7	6
	Uranium	1		(6		)	Discounted cash flow	Average forward uranium pricing($/pound)^(b)	35 - 43	36
Ameren Missouri	Fuel oils	$	7	$	(4	)	Option model	Volatilities(%)^(b)	9 - 20	17
							Discounted cash flow	Counterparty credit risk(%)^(c)(d)	.26 - 3	2
	Natural gas	1		(1		)	Option model	Volatilities(%)^(b)	5 - 29	24
								Nodal basis($/mmbtu)^(c)	(0.40) - (0.20)	(0.40)
							Discounted cash flow	Nodal basis($/mmbtu)^(c)	(0.10)	(e)
								Counterparty credit risk(%)^(c)(d)	0.64 - 0.83	0.77
								Ameren Missouri credit risk(%)^(c)(d)	2 - 3	2
	Power^(f)	29		(1		)	Discounted cash flow	Average forward peak and off-peak power pricing - forwards/swaps($/MWh)^(c)	27 - 43	33
								Estimated auction price for FTRs($/MW)^(b)	(103) - 1790	660
								Nodal basis($/MWh)^(c)	(4) - (1)	(4)
								Counterparty credit risk(%)^(c)(d)	0.22 - 3	0.73
								Ameren Missouri credit risk(%)^(c)(d)	3	(e)
	Uranium	1		(6		)	Discounted cash flow	Average forward uranium pricing($/pound)^(b)	35 - 43	36
Ameren Illinois	Power^(f)	$	—	$	(94	)	Discounted cash flow	Average forward peak and off-peak power pricing - forwards/swaps($/MWh)^(b)	27 - 37	30
								Nodal basis($/MWh)^(b)	(5) - (1)	(3)
								Ameren Illinois credit risk(%)^(c)(d)	3	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)^(b)	4 - 7	5
								Escalation rate(%)^(b)(g)	4 - 5	4
							Contract price allocation	Estimated renewable energy credit costs($/credit)^(b)	5 - 7	6



		Fair Value								Weighted
		Assets		Liabilities			Valuation Technique	Unobservable Input	Range	Average
Level 3 Derivative asset and liability - commodity contracts^(a):
Ameren	Fuel oils	$	8	$	(3	)	Discounted cash flow	Escalation rate(%)^(b)	.21 - .60	.44
								Counterparty credit risk(%)^(c)(d)	.12 - 1	1
								Ameren credit risk(%)^(c)(d)	2	(e)
							Option model	Volatilities(%)^(b)	7 - 27	24
	Power^(f)	14		(114		)	Discounted cash flow	Average forward peak and off-peak power pricing - forwards/swaps($/MWh)^(c)	22 - 47	31
								Estimated auction price for FTRs($/MW)^(b)	(281) - 1,851	178
								Nodal basis($/MWh)^(c)	(5) - (1)	(3)
								Counterparty credit risk(%)^(c)(d)	.22 - 1	1
								Ameren credit risk(%)^(c)(d)	2 - 5	5
							Fundamental energy production model	Estimated future gas prices($/mmbtu)^(b)	4 - 8	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)^(b)	5 - 7	6
	Uranium	—		(2		)	Discounted cash flow	Average forward uranium pricing($/pound)^(b)	43 - 46	44
Ameren Missouri	Fuel oils	$	8	$	(3	)	Discounted cash flow	Escalation rate(%)^(b)	.21 - .60	.44
								Counterparty credit risk(%)^(c)(d)	.12 - 1	1
								Ameren Missouri credit risk(%)^(c)(d)	2	(e)
							Option model	Volatilities(%)^(b)	7 - 27	24
	Power^(f)	14		(3		)	Discounted cash flow	Average forward peak and off-peak power pricing - forwards/swaps($/MWh)^(c)	24 - 56	36
								Estimated auction price for FTRs($/MW)^(b)	(281) - 1,851	178
								Nodal basis($/MWh)^(c)	(5) - (1)	(2)
								Counterparty credit risk(%)^(c)(d)	.22 - 1	1
								Ameren Missouri credit risk(%)^(c)(d)	2	(e)
	Uranium	—		(2		)	Discounted cash flow	Average forward uranium pricing($/pound)^(b)	43 - 46	44
Ameren Illinois	Power^(f)	$	—	$	(111	)	Discounted cash flow	Average forward peak and off-peak power pricing - forwards/swaps($/MWh)^(b)	22 - 47	30
								Nodal basis($/MWh)^(b)	(5) - (1)	(3)
								Ameren Illinois credit risk(%)^(c)(d)	5	(e)
							Fundamental energy production model	Estimated future gas prices($/mmbtu)^(b)	4 - 8	6
							Contract price allocation	Estimated renewable energy credit costs($/credit)^(b)	5 - 7	6

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. Ameren recorded no gains or losses in the first nine months of 2013 or 2012 related to valuation adjustments for counterparty default risk. At September 30, 2013, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $4 million, less than $1 million, and $4 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. At December 31, 2012, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $7 million, less than $1 million, and $7 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, 2013:



		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
Ameren	Derivative assets - commodity contracts^(a):
	Fuel oils	$	1	$	—	$	7	$	8
	Natural gas	—		—		1		1
	Power	—		2		29		31
	Uranium	—		—		1		1
	Total derivative assets - commodity contracts	$	1	$	2	$	38	$	41
	Nuclear Decommissioning Trust Fund^(b):
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	309		—		—		309
	Debt securities:
	Corporate bonds	—		45		—		45
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		90		—		90
	Asset-backed securities	—		9		—		9
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	311	$	147	$	—	$	458
	Total Ameren	$	312	$	149	$	38	$	499
Ameren	Derivative assets - commodity contracts^(a):
Missouri	Fuel oils	$	1	$	—	$	7	$	8
	Natural gas	—		—		1		1
	Power	—		2		29		31
	Uranium	—		—		1		1
	Total derivative assets - commodity contracts	$	1	$	2	$	38	$	41
	Nuclear Decommissioning Trust Fund^(b):
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	309		—		—		309
	Debt securities:
	Corporate bonds	—		45		—		45
	Municipal bonds	—		2		—		2
	U.S. treasury and agency securities	—		90		—		90
	Asset-backed securities	—		9		—		9
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	311	$	147	$	—	$	458
	Total Ameren Missouri	$	312	$	149	$	38	$	499
Liabilities:
Ameren	Derivative liabilities - commodity contracts^(a):
	Fuel oils	$	—	$	—	$	4	$	4
	Natural gas	5		69		1		75
	Power	—		2		95		97
	Uranium	—		—		6		6
	Total Ameren	$	5	$	71	$	106	$	182
Ameren	Derivative liabilities - commodity contracts^(a):
Missouri	Fuel oils	$	—	$	—	$	4	$	4
	Natural gas	5		7		1		13
	Power	—		2		1		3
	Uranium	—		—		6		6
	Total Ameren Missouri	$	5	$	9	$	12	$	26
Ameren	Derivative liabilities - commodity contracts^(a):
Illinois	Natural gas	$	—	$	62	$	—	$	62
	Power	—		—		94		94
	Total Ameren Illinois	$	—	$	62	$	94	$	156



		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
Ameren	Derivative assets - commodity contracts^(a):
	Fuel oils	$	4	$	—	$	8	$	12
	Natural gas	—		2		—		2
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	4	$	3	$	22	$	29
	Nuclear Decommissioning Trust Fund^(b):
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	264		—		—		264
	Debt securities:
	Corporate bonds	—		47		—		47
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		81		—		81
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	265	$	141	$	—	$	406
	Total Ameren	$	269	$	144	$	22	$	435
Ameren	Derivative assets - commodity contracts^(a):
Missouri	Fuel oils	$	4	$	—	$	8	$	12
	Natural gas	—		1		—		1
	Power	—		1		14		15
	Total derivative assets - commodity contracts	$	4	$	2	$	22	$	28
	Nuclear Decommissioning Trust Fund^(b):
	Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:
	U.S. large capitalization	264		—		—		264
	Debt securities:
	Corporate bonds	—		47		—		47
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		81		—		81
	Asset-backed securities	—		11		—		11
	Other	—		1		—		1
	Total Nuclear Decommissioning Trust Fund	$	265	$	141	$	—	$	406
	Total Ameren Missouri	$	269	$	143	$	22	$	434
Ameren	Derivative assets - commodity contracts^(a):
Illinois	Natural gas	$	—	$	1	$	—	$	1



		Net derivative commodity contracts
Three Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at July 1, 2013	$	3		$	(a)		$	3
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		1			(a)			1
Total realized and unrealized gains (losses)		1			(a)			1
Purchases		1			(a)			1
Sales		(1	)		(a)			(1	)
Settlements		(1	)		(a)			(1	)
Ending balance at September 30, 2013	$	3		$	(a)		$	3
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	1		$	(a)		$	1
Natural gas:
Beginning balance at July 1, 2013	$	(1	)	$	2		$	1
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—			(2	)		(2	)
Total realized and unrealized gains (losses)		—			(2	)		(2	)
Purchases		1			—			1
Ending balance at September 30, 2013	$	—		$	—		$	—
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	—		$	(1	)	$	(1	)
Power:
Beginning balance at July 1, 2013	$	37		$	(80	)	$	(43	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(3	)		(17	)		(20	)
Total realized and unrealized gains (losses)		(3	)		(17	)		(20	)
Sales		1			—			1
Settlements		(6	)		3			(3	)
Transfers into Level 3		(1	)		—			(1	)
Ending balance at September 30, 2013	$	28		$	(94	)	$	(66	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	(2	)	$	(16	)	$	(18	)
Uranium:
Beginning balance at July 1, 2013	$	(3	)	$	(a)		$	(3	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—			(a)			—
Total realized and unrealized gains (losses)		—			(a)			—
Purchases		(2	)		(a)			(2	)
Ending balance at September 30, 2013	$	(5	)	$	(a)		$	(5	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	(2	)	$	(a)		$	(2	)

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, 2012:



		Net derivative commodity contracts
Three Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at July 1, 2012	$	3		$	(a)		$	3
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		1			(a)			1
Total realized and unrealized gains (losses)		1			(a)			1
Purchases		2			(a)			2
Sales		(1	)		(a)			(1	)
Ending balance at September 30, 2012	$	5		$	(a)		$	5
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	2		$	(a)		$	2
Power^(b):
Beginning balance at July 1, 2012	$	26		$	(221	)	$	(81	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(4	)		2			(6	)
Total realized and unrealized gains (losses)		(4	)		2			(6	)
Sales		(1	)		—			(1	)
Settlements		(4	)		54			(1	)
Transfers out of Level 3		(2	)		—			(2	)
Ending balance at September 30, 2012	$	15		$	(165	)	$	(91	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	(5	)	$	(2	)	$	(7	)
Uranium:
Beginning balance at July 1, 2012	$	(1	)		(a)		$	(1	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(1	)		(a)			(1	)
Total realized and unrealized gains (losses)		(1	)		(a)			(1	)
Ending balance at September 30, 2012	$	(2	)		(a)		$	(2	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	(1	)		(a)		$	(1	)



		Net derivative commodity contracts
Nine Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2013	$	5		$	(a)		$	5
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(1	)		(a)			(1	)
Total realized and unrealized gains (losses)		(1	)		(a)			(1	)
Purchases		2			(a)			2
Sales		(1	)		(a)			(1	)
Settlements		(2	)		(a)			(2	)
Ending balance at September 30, 2013	$	3		$	(a)		$	3
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	—		$	(a)		$	—
Natural gas:
Beginning balance at January 1, 2013	$	—		$	—		$	—
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		—			(1	)		(1	)
Total realized and unrealized gains (losses)		—			(1	)		(1	)
Purchases		—			1			1
Ending balance at September 30, 2013	$	—		$	—		$	—
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	—		$	—		$	—
Power:
Beginning balance at January 1, 2013	$	11		$	(111	)	$	(100	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		3			(2	)		1
Total realized and unrealized gains (losses)		3			(2	)		1
Purchases		40			—			40
Sales		1			—			1
Settlements		(28	)		19			(9	)
Transfers into Level 3		(3	)		—			(3	)
Transfers out of Level 3		4			—			4
Ending balance at September 30, 2013	$	28		$	(94	)	$	(66	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	—		$	(7	)	$	(7	)
Uranium:
Beginning balance at January 1, 2013	$	(2	)	$	(a)		$	(2	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(2	)		(a)			(2	)
Total realized and unrealized gains (losses)		(2	)		(a)			(2	)
Purchases		(2	)		(a)			(2	)
Settlements		1			(a)			1
Ending balance at September 30, 2013	$	(5	)	$	(a)		$	(5	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013	$	(2	)	$	(a)		$	(2	)

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, 2012:



		Net derivative commodity contracts
Nine Months		Ameren Missouri			Ameren Illinois			Ameren
Fuel oils:
Beginning balance at January 1, 2012	$	3		$	(a)		$	3
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(1	)		(a)			(1	)
Total realized and unrealized gains (losses)		(1	)		(a)			(1	)
Purchases		4			(a)			4
Sales		(2	)		(a)			(2	)
Settlements		(1	)		(a)			(1	)
Transfers into Level 3		2			(a)			2
Ending balance at September 30, 2012	$	5		$	(a)		$	5
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	(1	)	$	(a)		$	(1	)
Natural gas:
Beginning balance at January 1, 2012	$	(14	)	$	(160	)	$	(174	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(2	)		(26	)		(28	)
Total realized and unrealized gains (losses)		(2	)		(26	)		(28	)
Settlements		1			16			17
Transfers out of Level 3		15			170			185
Ending balance at September 30, 2012	$	—		$	—		$	—
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	7		$	—		$	7
Power^(b):
Beginning balance at January 1, 2012	$	21		$	(140	)	$	81
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		5			(219	)		(174	)
Total realized and unrealized gains (losses)		5			(219	)		(174	)
Purchases		22			—			22
Sales		(1	)		—			(1	)
Settlements		(28	)		194			(15	)
Transfers out of Level 3		(4	)		—			(4	)
Ending balance at September 30, 2012	$	15		$	(165	)	$	(91	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	(1	)	$	(187	)	(c) $	(171	)
Uranium:
Beginning balance at January 1, 2012	$	(1	)	$	(a)		$	(1	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities		(1	)		(a)			(1	)
Total realized and unrealized gains (losses)		(1	)		(a)			(1	)
Ending balance at September 30, 2012	$	(2	)	$	(a)		$	(2	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012	$	(1	)	$	(a)		$	(1	)

that only the suppliers would be required to post collateral. Therefore, Ameren Missouri and Marketing Company, as winning suppliers in the RFP process, may be required to post collateral. As of December 31, 2012, and September 30, 2013, there were no collateral postings required of Ameren Missouri or Marketing Company related to the Illinois power procurement agreements.

Marketing Company Sale of Trade Receivables to Ameren Illinois

In accordance with the Illinois Public Utilities Act, beginning in June 2012, Ameren Illinois is required to purchase alternative retail electric suppliers’ receivables relating to Ameren Illinois’ delivery service customers who elected to receive power supply from the alternative retail electric supplier. Marketing Company sells and Ameren Illinois purchases trade receivables relating to the power supply of residential customers using Marketing Company as their alternative retail electric supplier. Marketing Company has no continuing involvement with or control over the trade receivables after the sale is completed to Ameren Illinois, and neither company has any restrictions on the assets associated with these purchase and sale transactions. As of September 30, 2013, Ameren Illinois’ payable to Marketing Company for the purchase of trade receivables totaled $17 million. During the nine months ended September 30, 2013, Ameren Illinois purchased $115 million of trade receivables from Marketing Company at a discount of $2 million. Marketing Company’s receivable from Ameren Illinois as well as Ameren Illinois’ payable to Marketing Company are eliminated in Ameren’s consolidated financial statements. After the New AER divestiture is complete, these transactions will no longer be eliminated in Ameren’s consolidated financial statements.

Parent Company Guarantees

In the ordinary course of business, Ameren (parent) enters into various agreements providing financial assurance to third parties on behalf of its subsidiaries. Such agreements include, for example, guarantees and letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit and reducing the amount of cash collateral required to be posted. These agreements guarantee performance by Ameren's subsidiaries of obligations already reflected on Ameren's consolidated balance sheet.

Upon the divestiture of New AER, the transaction agreement with IPH requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture and provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. 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 will be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which

Dynegy will, among other things, guarantee IPH's indemnification obligations for a period of up to 24 months after the closing. See Note 2 - Divestiture Transactions and Discontinued Operations.

At September 30, 2013, Ameren had a total of $192 million in guarantees outstanding, excluding a guarantee for Medina Valley related to the amended put option agreement. This guarantee expired in October 2013 with the closing of Genco’s sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. See Note 2 - Divestiture Transactions and Discontinued Operations for further discussion of the put option agreement. See below for further discussion of the outstanding guarantees:

•

$154 million related to Ameren's Merchant Generation segment, primarily for Marketing Company as support for physically and financially settled power transactions with its counterparties. As of September 30, 2013, this amount does not represent an incremental consolidated Ameren obligation; rather, it represents Ameren parental guarantees of subsidiary obligations to third parties, which may include affiliates, in order to allow the subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Ameren's estimated exposure for obligations under transactions covered by these guarantees was $25 million at September 30, 2013, which represents the total amount Ameren (parent) could be required to fund based on September 30, 2013 market prices.


•	$25 million provided to a clearing broker acting as futures commission merchant for the clearing of certain power, natural gas, and fuels commodity transactions for AER.


•	$13 million related to requirements for asset transactions, leasing, Medina Valley transactions through MISO and other agreements. At September 30, 2013, Ameren estimated it had no exposure to any of these guarantees.

Additionally, at September 30, 2013, Ameren had issued letters of credit totaling $14 million as credit support to certain subsidiaries.

Miscellaneous Support Services

Ameren Missouri and Ameren Illinois provide storm-related and miscellaneous support services to each other on an as- needed basis. Ameren Illinois provided to Ameren Missouri $2 million in storm-related support services during the nine months ended September 30, 2013. Ameren Missouri provided to Ameren Illinois $1 million in miscellaneous support services during the three and nine months ended September 30, 2013. Ameren Missouri provided to Ameren Illinois $1 million in miscellaneous support services during the nine months ended September 30, 2012. These amounts are reflected in “Operating Revenues - Other” on the statement of income and comprehensive income.

Money Pools

See Note 4 - Short-term Debt and Liquidity for a discussion of affiliate borrowing arrangements.



				Three Months				Nine Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2013	$	(b)	$	(a)	$	1	$	(a)
agreements with Ameren Illinois		2012		(b)		(a)		(b)		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2013		4		(b)		15		1
rent and facility services		2012		5		(b)		14		1
Ameren Missouri and Genco gas	Operating Revenues	2013		(b)		(a)		1		(a)
transportation agreement		2012		(b)		(a)		1		(a)
Transmission services agreement	Operating Revenues	2013		(a)		11		(a)		24
with Marketing Company		2012		(a)		5		(a)		11
Total Operating Revenues		2013	$	4	$	11	$	17	$	25
		2012		5		5		15		12
Ameren Illinois power supply	Purchased Power	2013	$	(a)	$	46	$	(a)	$	94
agreements with Marketing Company		2012		(a)		83		(a)		243
Ameren Illinois power supply	Purchased Power	2013		(a)		(b)		(a)		1
agreements with Ameren Missouri		2012		(a)		(b)		(a)		(b)
Total Purchased Power		2013	$	(a)	$	46	$	(a)	$	95
		2012		(a)		83		(a)		243
Ameren Services support services	Other Operations and Maintenance	2013	$	25	$	22	$	85	$	70
agreement		2012		26		22		81		67
Insurance premiums^(c)	Other Operations and Maintenance	2013		(b)		(a)		(b)		(a)
		2012		(b)		(a)		(b)		(a)
Total Other Operations and		2013	$	25	$	22	$	85	$	70
Maintenance Expenses		2012		26		22		81		67
Money pool borrowings (advances)	Interest Charges	2013	$	(b)	$	(b)	$	$1	$	(b)
		2012		(b)		(b)		(b)		(b)

To supply a portion of the fuel requirements of our energy centers, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We also have entered into various long-term commitments for purchased power and natural gas for distribution. The table below presents our estimated fuel, purchased power, and other commitments at September 30, 2013. Ameren’s and Ameren Missouri’s purchased power obligations include a 102-megawatt power purchase agreement with a wind farm operator that expires in 2024. Ameren’s and Ameren Illinois’ purchased power obligations include the Ameren Illinois power purchase agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services at September 30, 2013. Ameren's and Ameren Illinois' Other column also include obligations related to IEIMA. In addition, the Other column includes Ameren's and Ameren Missouri's obligations related to energy efficiency programs under the MEEIA as approved by the MoPSC's December 2012 electric rate order. The order provides that, beginning in 2013, Ameren Missouri will invest approximately $147 million over three years for energy efficiency programs.

chemicals or hazardous materials (including wastes) require release prevention plans and emergency response procedures.

In addition to existing environmental laws and regulations, including the Illinois MPS that applies to AER's coal-fired energy centers in Illinois, the EPA is developing regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, Ameren Missouri, and AER, that operate coal-fired energy centers. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions from new energy centers; revised national ambient air quality standards for fine particulates, SO_2, and NO_x emissions; the CSAPR, which would have required further reductions of SO₂ emissions and NO_x emissions from energy centers; a regulation governing management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from energy centers; revised NSPS for particulate matter, SO₂, and NO_x emissions from new sources; new effluent standards applicable to discharges from steam-electric generating units; and new regulations under the Clean Water Act that could require significant capital expenditures such as new water intake structures or cooling towers at our energy centers. The EPA is expected to propose CO₂ limits for existing fossil fuel-fired electric generation units in the future. These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia Circuit in August 2012. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and increased operating costs over the next five to ten years for Ameren, Ameren Missouri and AER. Compliance with these environmental laws and regulations could be prohibitively expensive. If they are, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.

The estimates in the tables below contain all of the known capital costs to comply with existing environmental regulations, including the CAIR, and our assessment of the potential impacts of the MATS and of the EPA's proposed regulation for CCR as of September 30, 2013. In addition, the estimates assume that CCR will continue to be regarded as nonhazardous. The estimates do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures or the impact of the effluent standards applicable to steam-electric generating units that the EPA proposed in April 2013, as the technology requirements ultimately to be selected in these final rules are not yet known. The estimates shown in the tables below could change significantly depending upon a variety of factors including:


•	Ameren’s divestiture of its Merchant Generation business;


•	additional or modified federal or state requirements;


•	further regulation of greenhouse gas emissions;


•	revisions to CAIR or reinstatement of CSAPR;


•	delays or accelerations of rulemaking and implementation by the EPA or state agencies;


•	new national ambient air quality standards, new standards intended to achieve national ambient air quality standards, or changes to existing standards for ozone, fine particulates, SO₂, and NO_x emissions;


•	additional or new rules governing air pollutant transport;


•	regulations or requirements under the Clean Water Act regarding cooling water intake structures or effluent standards;


•	finalized regulations classifying CCR as being hazardous or imposing additional requirements on the management of CCR;


•	new limitations or standards under the Clean Water Act applicable to discharges from steam-electric generating units;


•	new technology;


•	changes in expected power prices;


•	variations in costs of material or labor; and


•	alternative compliance strategies or investment decisions.

Continuing Operations:



	2013		2014 - 2017					2018 - 2022					Total
AMO^(a)	$	105	$	215	-	$	260	$	795	-	$	975	$	1,115	-	$	1,340


(a)	Ameren Missouri’s expenditures are expected to be recoverable from ratepayers.

Discontinued Operations:



	2013		2014 - 2017					2018 - 2022					Total
Genco^(a)	$	30	$	100	-	$	125	$	220	-	$	270	$	350	-	$	425
AERG	5		20		-	25		20		-	25		45		-	55
Total^(b)	$	35	$	120	-	$	150	$	240	-	$	295	$	395	-	$	480


(a)	Includes estimated costs of approximately $20 million annually, excluding capitalized interest, from 2013 through 2017 for construction of two scrubbers at the Newton energy center.


(b)	Assumes the Merchant Generation facilities are owned by Ameren.

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

Clean Air Act

Both federal and state laws require significant reductions in SO₂and NO_x emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO₂ and NO_x emissions (the CAIR). The CAIR requires generating facilities in 28 states, including Missouri and Illinois, and the District of Columbia, to participate in cap-and-trade programs to reduce annual SO₂emissions, annual NO_x emissions, and ozone season NO_x emissions.

In December 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the CAIR to the EPA for

further action to remedy the rule's flaws, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR. In August 2012, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that vacated the CSAPR in its entirety, finding that the EPA exceeded its authority in imposing the CSAPR's emission limits on states. In March 2013, the EPA and certain environmental groups filed an appeal of the Court of Appeals’ remand of CSAPR to the United States Supreme Court. The United States Supreme Court has agreed to consider the appeal and is expected to issue a ruling on the appeal during its current term, which ends in June 2014. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the United States Supreme Court overturns the decision to vacate the CSAPR.

In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and for the first time require continuous monitoring systems for hydrogen chloride, mercury, and particulate matter. The MATS do not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant; however in certain cases, emission compliance can be achieved by averaging emissions from similar electric generating units at the same power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016. Ameren Missouri's Labadie and Meramec energy centers requested and were granted extensions to April 2016 to comply with the MATS.

Separately, in December 2012, the EPA issued a final rule that made the national ambient air quality standard for fine particulate matter more stringent. States must develop control measures designed to reduce the emission of fine particulate matter below required levels to achieve compliance with the new standard. Such measures may or may not apply to energy centers but could require reductions in SO₂ and NO_x emissions. States are required to demonstrate compliance with the rule by 2020, or 2025 if an extension of time to achieve compliance is granted. Ameren Missouri and AER are currently evaluating the new standard while the states of Missouri and Illinois develop their attainment plans.

In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standards for ozone. The EPA is required to revisit these standards for ozone again in 2013. The states of Illinois and Missouri will be required to develop attainment plans to comply with the 2008 ambient air quality standards for ozone, which could result in additional emission control requirements for power plants by 2020. Ameren, Ameren Missouri and AER continue to assess the impacts of these new standards.

In July 2013, the EPA issued a final rule designating portions of the United States, including parts of Illinois and Missouri, as nonattainment for the national ambient air quality standard for SO₂. The designations became effective in October 2013, and the states must develop plans in the next 18 months to reduce emissions so that they can achieve the ambient air quality standards within five years. Ameren, Ameren Missouri and AER are assessing the impact of this designation.

Ameren Missouri's current environmental compliance plan for air emissions from its energy centers includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. In July 2011, Ameren Missouri contracted to procure significantly greater volumes of lower-sulfur-content coal than Ameren Missouri's energy centers had historically burned, which allowed Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO₂ emissions. Currently, Ameren Missouri's compliance plan assumes the installation of two scrubbers, mercury control technology, and precipitator upgrades at multiple energy centers within its coal-fired fleet during the next 10 years. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the MATS and other recently finalized or proposed EPA regulations.

In September 2012, the Illinois Pollution Control Board granted AER a variance to extend compliance dates for SO₂ emission levels contained in the MPS through December 31, 2019, subject to certain conditions described below. The Illinois Pollution Control Board approved AER's proposed plan to restrict its SO₂ emissions through 2014 to levels lower than those previously required by the MPS to offset any environmental impact from the variance. The Illinois Pollution Control Board's order also included the following provisions:


•	A schedule of milestones for completion of various aspects of the installation and completion of the scrubber projects at Genco's Newton energy center; the first milestone relates to the completion of engineering design by July 2015 while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019.

•

A requirement for AER to refrain from operating the Meredosia and Hutsonville energy centers through December 31, 2020; however, this restriction does not impact Genco's ability, or Ameren’s ability after the divestiture of New AER occurs, to make the Meredosia energy center available for any parties that may be interested in repowering one of its units to create an oxy-fuel combustion coal-fired energy center designed for permanent carbon dioxide capture and storage.

See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of New AER and a request filed with the Illinois Pollution Control Board for a variance in favor of IPH on the same material terms as the Illinois MPS variance granted to AER in September 2012.

Under the MPS, AER is required to reduce mercury, NO_xand SO₂ emissions with declining limits that started in 2009 for mercury and in 2010 for NO_x and SO₂.The final NO_x limit became effective in 2012. The final mercury limit will become effective in 2015 and the final SO₂ limit will become effective by the end of 2019. The Illinois Pollution Control Board's September 2012 variance gives AER additional time for economic recovery and related power price improvements necessary to support scrubber installations and other pollution controls at some of AER's energy centers. To comply with the MPS and other air emissions laws and regulations, AER is installing equipment designed to reduce its emissions of mercury, NO_x, and SO₂. AER has installed three scrubbers at two energy centers. Two additional scrubbers are being constructed at the Newton energy center. AER will continue to review and adjust its compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, emission standards required under environmental laws and regulations, and compliance technologies, among other factors.

Environmental compliance costs could be prohibitive at some of Ameren's, Ameren Missouri's and AER's energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.

Emission Allowances

The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NO_x budget trading program, and the CAIR. Environmental regulations, including those relating to the timing of the installation of pollution control equipment, fuel mix, and the level of operations will have a significant impact on the number of allowances required for ongoing operations. The CAIR uses the acid rain program's allowances for SO₂emissions and created annual and ozone season NO_x allowances. Ameren and Ameren Missouri expect to have adequate allowances for 2013 to avoid needing to make external purchases to comply with these programs.

Greenhouse Gas Regulation

State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions. Potential impacts from any such legislation or regulation could vary, depending upon proposed CO₂ emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO₂. The enactment of a law that restricts emissions of CO₂ or requires energy centers to purchase allowances for CO₂ emissions could result in a significant rise in rates for electricity and thereby household costs. The burden could fall particularly hard on electricity consumers and upon the economy

in the Midwest because of the region's reliance on electricity generated by coal-fired power plants. Natural gas emits about half as much CO₂ as coal when burned to produce electricity. Therefore, greenhouse gas regulations could cause the conversion of coal-fired power plants to natural gas, or the construction of new natural gas-fired plants to replace coal-fired power plants. As a result, economy wide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas.

In December 2009, the EPA issued its “endangerment finding” under the Clean Air Act, which stated that greenhouse gas emissions, including CO₂, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA issued the “Tailoring Rule,” which established new higher emission thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permit upon renewal. Currently, all Ameren energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology to address greenhouse gas emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld the Tailoring Rule. Industry groups and a coalition of states filed petitions in April 2013 requesting that the United States Supreme Court review the circuit court’s decision upholding the Tailoring Rule. In October 2013, the United States Supreme Court granted the petition agreeing to consider whether the Clean Air Act authorizes the EPA to regulate emissions of greenhouse gases from stationary sources, including power plants, as a result of the EPA’s determination to regulate greenhouse gas emissions from motor vehicles. A ruling is expected in 2014.

In June 2013, the Obama Administration announced that it had directed the EPA to set CO₂ emissions standards for both new and existing power plants. The EPA proposed revised CO₂ emissions regulations for new electricity generating units in September 2013. The proposed standards would establish separate emissions limits for new natural gas-fired plants and new coal-fired plants. In addition, the Obama Administration had

directed the EPA to propose a CO₂ emissions standard for existing power plants by June 2014 and to finalize such standard by June 2015. Currently, the Ameren Companies are unable to predict the outcome or impacts of such future regulations.

Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address alleged damages resulting from greenhouse gas emissions. In March 2012, the United States District Court for the Southern District of Mississippi dismissed the Comer v. Murphy Oil lawsuit, which alleged that CO₂ emissions from several industrial companies, including Ameren Missouri, Genco and AERG, created atmospheric conditions that intensified Hurricane Katrina, thereby causing property damage. In May 2013, the dismissal of the lawsuit was affirmed by the United States Court of Appeals for the Fifth Circuit.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. These compliance costs could be prohibitive at some of our energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets. To the extent Ameren Missouri requests recovery of these costs through rates, its regulators might delay or deny timely recovery of these costs. As a result, mandatory limits on the emission of greenhouse gases could have a material adverse impact on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity.

NSR and Clean Air Litigation

The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications. The EPA's inquiries focus on whether projects performed at power plants triggered various permitting requirements and the installation of pollution control equipment.

Commencing in 2005, Genco received a series of information requests from the EPA pursuant to Section 114(a) of the Clean Air Act. The requests sought detailed operating and maintenance history data with respect to Genco's Coffeen, Hutsonville, Meredosia, Newton, and Joppa energy centers and AERG's E.D. Edwards and Duck Creek energy centers. In August 2012, Genco received a Notice of Violation from the EPA alleging violations of permitting requirements including Title V of the Clean Air Act. The EPA contends that projects performed in 1997, 2006, and 2007 at Genco's Newton energy center violated federal law. Ameren believes its defenses to the allegations at Genco described in the Notice of Violation are meritorious. A recent decision by the United States Court of Appeals for the Seventh Circuit held that similar claims older than five years were barred by the statute of limitations. If not reversed or overturned, this decision may provide an additional defense to the allegations in

the Newton energy center Notice of Violation. Ameren is unable to predict the outcome of this matter.

Following the issuance of a Notice of Violation 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. In January 2012, the district court granted, in part, Ameren Missouri's motion to dismiss various aspects of the EPA's penalty claims. The EPA's claims for unspecified injunctive relief remain. Trial in this matter is currently scheduled for January 2015. Ameren Missouri believes its defenses are meritorious and will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.

Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren and Ameren Missouri. A resolution 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 March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25% of that water exclusively for cooling. Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant's intake screens or to reduce intake velocity to a specified level. The proposed rule also requires existing power plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in November 2013, with compliance expected within eight years thereafter. All coal-fired, nuclear, and combined cycle energy centers at Ameren, Ameren Missouri and AER with cooling water systems are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities, as other technology options potentially could meet the site-specific standards. The final rule could have an adverse effect on our 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.

In April 2013, the EPA announced its proposal to revise the effluent limitation guidelines applicable to steam electric generating units under the Clean Water Act. Effluent limitation guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The proposed revision targets wastewater streams associated with fluegas desulfurization (i.e. scrubbers),

fly ash, bottom ash, fluegas mercury control, CCR leachate from landfills and impoundments, nonchemical metal cleaning, and gasification of fuels. The EPA’s proposal identifies several alternatives for addressing these waste streams, including best management practices for CCR impoundments. The EPA’s proposed rule raised several compliance options that would prohibit effluent discharges of certain, but not all, waste streams and impose more stringent limitations on certain components in wastewater discharges from power plants. If enacted as proposed, Ameren Missouri and AER would be subject to the revised limitations beginning as early as July 1, 2017, but no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impact on our operations if enacted as proposed. The EPA expects to issue a final rule in 2014.

Remediation

We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes 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 the federal or state governments as a potentially responsible party (PRP) at several contaminated sites.

As part of the transfer of generation assets by our rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003, Ameren Illinois’ predecessor companies contractually agreed to indemnify Genco and AERG for claims relating to pre-existing environmental conditions at the transferred sites. The plant transfer agreements between both Genco and Ameren Illinois and AERG and Ameren Illinois will be amended as part of the transaction agreement for Ameren to divest New AER to IPH. The agreements will specify that Medina Valley will assume any environmental liabilities associated with the Meredosia and Hutsonville energy centers. The agreements will also specify that Genco and AERG will no longer be indemnified by Ameren Illinois with respect to the environmental liabilities associated with Genco’s Newton and Coffeen energy centers and AERG’s E.D. Edwards and Duck Creek energy centers. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of New AER.

As of September 30, 2013, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois. These sites are in various stages of investigation, evaluation, remediation, and closure. Based on current estimated plans, Ameren Illinois could substantially conclude remediation efforts at most of these sites by 2018. The ICC permits 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 and properly incurred. Costs are subject to annual review by the ICC.

As of September 30, 2013, Ameren Missouri has one remaining former MGP site for which remediation is scheduled.

Remediation is complete at the other Ameren Missouri former MGP sites. Ameren Missouri does not currently have a rate rider mechanism that permits it to recover from utility customers remediation costs associated with MGP sites.

The following table presents, as of September 30, 2013, the estimated obligation to complete the remediation of these former MGP sites.



	Estimate				Recorded Liability^(a)
	Low		High		Recorded Liability^(a)
Ameren	$	251	$	337	$	251
Ameren Missouri	5		6		5
Ameren Illinois	246		331		246


(a)	Recorded liability represents the estimated minimum probable obligations, 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 utilized an off-site landfill, which Ameren Illinois did not own, in connection with its operation of the Coffeen energy center prior to the formation of Genco. While not currently mandated, Ameren Illinois may be required to perform certain remediation activities associated with that landfill. As of September 30, 2013, Ameren Illinois estimated the obligation related to the cleanup 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 a landfill, underground storage tanks, and a water treatment plant in Illinois. As of September 30, 2013, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.

Ameren Missouri has responsibility for the investigation and potential cleanup of two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other PRPs, is currently performing a site investigation. As of September 30, 2013, 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's other active federal agency-mandated cleanup site in Missouri is a site in Cape Girardeau. Ameren Missouri was a customer of an electrical equipment repair and disposal company that previously

operated a facility at this site. A trust was established in the early 1990s by several businesses and governmental agencies to fund the investigation and cleanup of this site, which was completed in 2005. Ameren Missouri anticipates that this trust fund will be sufficient to complete the remaining adjacent off-site cleanup, and it therefore has no recorded liability at September 30, 2013, for this site.

Ameren Missouri also has a federal agency mandate to complete an investigation for a site in Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, 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 that was once used as a landfill. Under the terms of an Administrative Order on Consent, Ameren Missouri joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2.

The Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted to the EPA, and a record of decision is expected in 2014. Once the EPA has approved the proposed site remedies, it will begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia's former chemical waste landfill in Sauget Area 2. As of September 30, 2013, Ameren Missouri estimated its obligation related to Sauget Area 2 at $0.3 million to $10 million. Ameren Missouri recorded a liability of $0.3 million to represent its estimated minimum obligation, 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, 2013, Ameren Missouri estimated the obligation related to the cleanup at $1.6 million to $4.5 million. Ameren Missouri recorded a liability of $1.6 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate.

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

Ash Management

There has been activity at both state and federal levels regarding additional regulation of CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy

centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric generating units would apply to ash ponds and CCR management and that it intended to align this proposal with the CCR rules proposed in May 2010. Additionally, in January 2010, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and AER are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. Ameren, Ameren Missouri and AER are evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted. See Note 2 - Divestiture Transactions and Discontinued Operations for information regarding AER’s AROs, which include those related to CCR storage facilities.

The Illinois EPA has issued violation notices with respect to groundwater conditions existing at Genco’s ash pond systems. AER filed a proposed rulemaking with the Illinois Pollution Control Board which, if approved, would provide for the systematic and eventual closure of ash ponds. In October 2013, the Illinois EPA filed a proposed rulemaking with the Illinois Pollution Control Board. AER has stayed its rulemaking efforts to allow the Illinois EPA proposed rulemaking to proceed. The rulemaking process could take several years to complete. During the first quarter of 2013, Genco and AERG revised their ARO fair value estimates relating to their ash ponds to reflect expected retirement dates. See Note 1 - Summary of Significant Accounting Policies for additional information related to our asset retirement obligations.

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. This resulted in significant flooding in the local area, which damaged a state park. The rebuilt Taum Sauk energy center became fully operational in April 2010.

Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. As of September 30, 2013, Ameren Missouri had an insurance receivable balance of $68 million. Ameren Missouri's results of operations, financial position and liquidity could be adversely affected if its remaining liability insurance claims are not paid by insurers.

In June 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, filed in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed that the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In January 2011, the district court ruled that the parties must first pursue alternative dispute resolution and enforced the forum selection clause of their coverage agreement. The forum selection clause requires use of New York law and effectively requires mandatory arbitration. Ameren Missouri appealed the January 2011 ruling to the United States Court of Appeals for the Eighth Circuit. In August 2012, the court of appeals remanded the case to the district court for consideration of whether Missouri public policy voids the forum selection clause. In September 2013, the district court ruled that Missouri public policy voids the forum selection clause.

Separately, in April 2012, Ameren Missouri sued a second insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the April 2012 litigation, which is pending in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. The insurance company filed a motion to compel arbitration, which the district court denied. In April 2013, the United States Court of Appeals for the Eighth Circuit affirmed the district court’s denial of the insurer’s motion and remanded the case to the district court.

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. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies with the average number of parties being 78 as of September 30, 2013. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.

The claims filed against Ameren, Ameren Missouri and Ameren Illinois allege injury from asbestos exposure during the plaintiffs' activities at our present or former energy centers. Former CIPS energy centers are now owned by Genco, and former CILCO energy centers are now owned by AERG. As a condition to the transfer of ownership of the CIPS and CILCO energy centers, CIPS and CILCO, now Ameren Illinois, contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising or existing from activities prior to the transfer. The plant transfer agreement between Genco and Ameren Illinois and the plant transfer agreement between AERG and Ameren Illinois each will be amended pursuant to the transaction agreement in which Ameren agrees to divest New AER to IPH. The amended plant transfer agreements will provide that Ameren Illinois will continue to retain asbestos exposure-related liabilities for claims arising or existing from activities prior to the transfer of the ownership of the

CIPS and CILCO energy centers to Genco and AERG. IPH will be responsible for any asbestos-related claims arising from activities that occur after IPH takes ownership of New AER. Any asbestos-related claims arising solely from activities post transfer of the energy centers from CIPS and CILCO to Genco and AERG, respectively, but prior to IPH taking ownership of New AER, of which there are currently none, will be retained by Ameren. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren's divestiture of AER.

The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of September 30, 2013:


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

At September 30, 2013, Ameren, Ameren Missouri and Ameren Illinois had liabilities of $15 million, $7 million, and $8 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, 2013, the trust fund balance was $23 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.

Ameren Illinois Municipal Taxes

Ameren Illinois received tax liability notices from the City of O'Fallon, Illinois relating to prior-period electric and natural gas municipal taxes. The city alleges that Ameren Illinois failed to collect prior-period taxes from more than 2,400 accounts primarily in annexed areas for the period 2004 through 2012. In July 2013, the O’Fallon city administrator issued an order stating that Ameren Illinois was liable to the City of O’Fallon for $4 million. In August 2013, Ameren Illinois filed an appeal and a stay of the O’Fallon city administrator’s order to the St. Clair County Circuit Court. In addition, in December 2012, the City of Peoria issued a tax liability notice alleging that Ameren Illinois failed to collect prior-period municipal taxes from certain accounts. In September 2013, a hearing officer issued an order stating that Ameren Illinois was liable to the City of Peoria for $0.5 million. Ameren Illinois plans to file an appeal and a stay of the order to the Peoria County Circuit Court. Ameren Illinois believes its defenses to the allegations are meritorious and will defend itself vigorously. As of September 30, 2013, Ameren

Illinois estimated its obligation at $1 million to $5 million. Ameren Illinois recorded a liability of $1 million to represent its estimated minimum obligation to the City of O'Fallon and the City of Peoria, as no other amount within the range was a better estimate.

In addition, at the end of 2012, five other cities issued tax liability notices alleging that Ameren Illinois failed to collect prior-period taxes from certain accounts. At this time, it is premature in Ameren Illinois' review of the additional notices received at the end of 2012 to reasonably estimate any likelihood of loss.

NOTE 11 - 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 Missouri and other companies that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established the fee that these companies pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatthour generated by those plants and sold. The NWPA also requires the DOE 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 and other companies have entered into standard contracts with the DOE, which is the agency responsible for implementing the NWPA. Consistent with the NWPA and its standard contract, Ameren Missouri collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway energy center.

Both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, however, no federal storage facility currently exists. Ameren Missouri has sufficient installed capacity at its Callaway energy center to store the spent nuclear fuel generated at Callaway through 2020 and has the capability for additional storage capacity for spent nuclear fuel generated through the end of the energy center’s current licensed life.

Until January 2009, the DOE program provided for spent nuclear fuel disposal to take place at a geologic repository to be constructed at Yucca Mountain, Nevada. In January 2009, the federal government announced that a repository at Yucca Mountain was unworkable and took steps to terminate the Yucca Mountain program, while acknowledging the federal government’s continuing obligation to dispose of companies’ spent nuclear fuel. In January 2012, an advisory commission established by the DOE issued its report of recommendations for the storage and disposal of spent nuclear fuel. The recommendations covered topics such as the approach to siting future nuclear waste management facilities, the transport and storage of spent fuel and high-level waste, options for waste disposal, institutional arrangements for managing spent nuclear fuel and high-level wastes, and changes needed in the handling of nuclear waste fees and of the Nuclear Waste Fund.

In January 2013, the DOE issued its plan for the management and disposal of spent nuclear fuel in response to the recommendation contained in the advisory commission's report. The DOE's plan calls for a pilot interim storage facility to begin operation with an initial focus on accepting spent nuclear fuel from shutdown reactor sites by 2021. By 2025, a larger interim storage facility would be available and would be co-located with the pilot facility. The plan also proposes to site a permanent geological repository to begin operation by 2048. 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 operation of the energy center.

As a result of the DOE's failure to begin to dispose of the spent nuclear fuel from nuclear energy centers and fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners have sued the DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed a breach of contract lawsuit to recover costs that it incurred through 2009. This amount included the cost of reracking the Callaway energy center’s spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes that Ameren Missouri would not have incurred had DOE performed its contractual obligations. In June 2011, the parties reached a settlement that included an annual reimbursement of Ameren Missouri’s spent fuel storage and related costs through at least 2013. In March 2013, Ameren Missouri submitted its 2012 costs to the DOE for reimbursement under the settlement agreement. Ameren Missouri expects to receive the 2012 cost reimbursement of $6 million during the fourth quarter of 2013. These costs were recorded in “Miscellaneous accounts and notes receivable” on Ameren’s and Ameren Missouri’s September 30, 2013 balance sheets.

In December 2011, Ameren Missouri filed a license extension application with the NRC to extend its Callaway energy center's operating license from 2024 to 2044. There is no deadline by which the NRC must act on this application. Among the rules that the NRC has historically relied upon in approving license extensions are rules dealing with the storage of spent nuclear fuel at the reactor site and with the NRC's confidence that permanent disposal of spent nuclear fuel will be available when needed. In a June 2012 decision, the United States Court of Appeals for the District of Columbia Circuit vacated these rules and remanded the case to the NRC, holding that the NRC's obligations under the National Environmental Policy Act required a more thorough environmental analysis in support of the NRC's waste confidence decision. In June 2012, a number of groups petitioned the NRC to suspend final licensing decisions in certain NRC licensing proceedings, including the Callaway energy center license extension, until the NRC completed its proceedings on the vacated rules. In August 2012, the NRC stated that it would not issue licenses dependent on the vacated rules until it appropriately addressed the court's remand. In September 2012, the NRC directed its staff to issue, within two years, a new waste confidence final environmental impact statement and a final rule to address the court's ruling. The newly created Waste Confidence Directorate within NRC now oversees the drafting of a new waste confidence environmental impact statement and rule, and its schedule presently provides for issuance of the final

environmental impact statement and final rule by no later than September 2014. Consistent with its schedule, the NRC, on September 13, 2013, issued for public comment the draft waste confidence generic environmental impact statement and its proposed waste confidence rule. If the Callaway energy center's license is extended, additional spent fuel storage will be required. Ameren Missouri plans to install a dry spent fuel storage facility at its Callaway energy center and intends to begin transferring spent fuel assemblies to this facility by 2016.

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 an assumed 40-year life of the nuclear center, ending with the expiration of the energy center's current operating license in 2024. 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. Decommissioning costs are included in the costs of service used to establish electric rates for Ameren Missouri's customers. These costs amounted to $7 million in each of the years 2013, 2012, and 2011. Every three years, the MoPSC requires Ameren

Missouri to file an updated cost study and funding analysis for decommissioning its Callaway energy center. Electric rates may be adjusted at such times to reflect changed estimates. If Ameren Missouri's operating license extension application is approved by the NRC, a revised funding analysis will be prepared and the rates charged to customers will be adjusted accordingly to reflect the operating license extension at the time of the next triennial cost study and funding analysis is approved by the MoPSC. Amounts collected from customers are deposited in an external trust fund to provide for the Callaway energy center's decommissioning. 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 nuclear decommissioning 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.

See Note 3 - Rate and Regulatory Matters for additional information related to the Callaway energy center.

Ameren has three reportable segments: Ameren Missouri, Ameren Illinois, and Merchant Generation. The Ameren Missouri segment for both Ameren and Ameren Missouri includes all 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 Merchant Generation segment for Ameren consists primarily of the operations or activities of AER, including Genco, EEI, AERG, and Marketing Company. Ameren intends to divest its Merchant Generation segment and, therefore, has excluded that segment’s information below. See Note 2 - Divestiture Transactions and Discontinued Operations for information regarding the Merchant Generation segment. The category called Other primarily includes Ameren parent company activities, Ameren Services, and ATXI. The Other category also includes activities previously included in the Merchant Generation segment that will be retained by Ameren after the divestiture of New AER and the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers are complete. See Note 2 - Divestiture Transactions and Discontinued Operations for information regarding the assets and liabilities to be retained by Ameren after the divestitures.

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 contained in the Form 10-K, and also the Risk Factors contained in the Form 10-K and in the Form 10-Q for the quarterly period ended March 31, 2013. 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 the various segments of our business 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.


•	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 operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.


•	AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes.

of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. Immediately after receipt of FERC approval, Genco completed its sale of these gas-fired energy centers to Medina Valley and received additional cash proceeds of $37.5 million. Medina Valley has entered into an agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. Ameren expects this third-party sale of these gas-fired energy centers to close by the end of 2013, subject to FERC and other regulatory approvals. See Note 2 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for additional information regarding these divestitures.

As a result of the transaction agreement with IPH and Ameren’s plan to sell its Elgin, Gibson City, and Grand Tower gas-fired energy centers, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation beginning March 14, 2013. Therefore, Ameren has segregated New AER’s and the Elgin, Gibson City, and Grand Tower gas-fired energy centers’ operating results, assets, and liabilities and presented them separately as discontinued operations for all periods disclosed 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 2 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, for additional information regarding that presentation.

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 Corporation was $302 million in the third quarter of 2013, compared with net income of $374 million in the third quarter of 2012. Net income attributable to Ameren Corporation from continuing operations was $305 million in the third quarter of 2013, compared with net income of $309 million in the third quarter of 2012. Net income attributable to Ameren Corporation increased to $252 million in the first nine months of 2013, from $182 million in the first nine months of 2012. Net income attributable to Ameren Corporation from continuing operations decreased to $464 million in the first nine months of 2013, from $507 million in the first nine months of 2012.

Net income from continuing operations at Ameren was unfavorably impacted in the third quarter and first nine months of

2013, compared with the same periods in 2012, by decreased electric demand resulting from summer temperatures that were cooler than last year’s warmer-than-normal temperatures, partially offset in both periods by the absence of the collar adjustment impact on Ameren Illinois earnings which came into effect with the hot summer weather in 2012, and partially offset in the nine-month period by increased natural gas demand in the first quarter of 2013. Additionally, a reduction in revenues at Ameren Missouri, resulting from a Missouri Court of Appeals decision regarding the FAC, reduced earnings between periods. Net income from continuing operations at Ameren was also unfavorably impacted in the first nine months of 2013, compared with the same period in 2012, by costs associated with the Callaway energy center's 2013 scheduled refueling and maintenance outage and by the absence in 2013 of a 2012 FERC-ordered Entergy refund, not included in the FAC, that reduced Ameren Missouri's purchased power expense and increased interest income. Net income from continuing operations at Ameren was favorably impacted in the third quarter and first nine months of 2013, compared with the same periods in 2012, by rate increases for Ameren Missouri electric and Ameren Illinois transmission service, both effective in January 2013, as well as higher Ameren Illinois electric delivery earnings. The latter reflected the absence, in 2013, of a 2012 required contribution, as well as increased rate base and a higher allowed return on equity under formula ratemaking.

Ameren continues to expect to complete the divestiture of its Merchant Generation business by the end of 2013. Completion of the divestiture of New AER to IPH requires FERC and FCC approvals. In October 2013, Ameren received FERC approval for the divestiture of New AER to IPH. The FCC approval was received in August 2013. Separately, as a condition to IPH’s obligation to complete the acquisition of New AER, the Illinois Pollution Control Board must approve the transfer to IPH of, or otherwise approve a variance in favor of IPH on the same material terms as, AER’s variance of the Illinois MPS. In May 2013, AER and IPH filed a transfer request with the Illinois Pollution Control Board, which was subsequently denied by the board on procedural grounds. On July 22, 2013, IPH, AER and Medina Valley, as current and future owners of the coal-fired energy centers, filed a request for a variance with the Illinois Pollution Control Board seeking materially the same relief as the existing AER variance. The Illinois Pollution Control Board has until late November 2013 to issue a decision. Immediately following receipt of FERC approval in October 2013, Genco completed the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. Medina Valley has entered into an agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. Ameren expects the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital, which is also subject to FERC and other regulatory approvals, will be completed by the end of 2013. Once the Merchant Generation business is divested, the resulting shift to a fully rate-regulated business is expected to substantially improve the predictability of our future earnings and cash flows.

With regard to our rate-regulated operations, a key strategic objective is to invest in and operate our businesses in a manner consistent with existing regulatory frameworks. We do this because healthy financial performance is critical to our shareholders, just as it is to our ability to undertake the significant operating and capital spending needed to meet customers’ energy needs and expectations. To meet this objective, we have been requesting and obtaining rate increases as needed, as well as aligning operating and capital spending consistent with regulatory outcomes and existing frameworks. As a result of these and other operational and cost containment initiatives, our electric rates have remained low, delivery system reliability has been enhanced, energy center availability has remained strong and our earned returns at our utilities have improved. To be positioned to invest so that we can meet our customers’ future energy needs and expectations, we have also been aggressively working to enhance regulatory frameworks. Modern, constructive regulatory frameworks, such as those we have in place for our FERC-regulated transmission and Illinois-regulated energy delivery businesses, support investment in utility infrastructure, benefiting our utilities and the communities we serve. We also continue to focus on developing additional rate-regulated opportunities for investment and growing rate base. Over the last few years, we have identified and advanced several new opportunities, including our Modernization Action Plan, which is accelerating improvements to Ameren Illinois’ electric and natural gas delivery systems, and new FERC-regulated transmission projects designed to improve reliability and efficiency. We expect successful execution of our strategy to result in meeting our customers’ future energy needs and expectations, earning fair returns on our investments, and earnings per share and dividend growth driven primarily by projected increases in rate base investments.

Ameren plans to invest approximately $2.2 billion in FERC-regulated electric transmission projects over the five-year period ending in 2017. ATXI's Illinois Rivers project is a major component of that plan. In August 2013, the ICC granted a certificate of public convenience and necessity and approved seven of a total of nine sections of the route and three of the proposed nine substations for the Illinois Rivers project. The ICC order indicated the project is necessary to address transmission and reliability needs in an efficient and equitable manner and that the project will benefit the development of a competitive electricity market. The ICC also indicated that ATXI is capable of constructing and managing the project and capable of financing it. In October 2013, the ICC granted ATXI’s request for rehearing to consider additional evidence regarding the two segments of the route and six substations that were not approved, as well as the requests for rehearing of certain other parties regarding two of the approved segments of the route. An order on rehearing is expected in March 2014.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Weather, economic conditions, the impacts of energy efficiency programs, and the actions of key customers

can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. The vast majority of Ameren's revenues are subject to state or federal regulation. This regulation has a material impact on the price we charge for our services. We principally use coal, nuclear fuel, natural gas, and oil for fuel in our operations. The prices for these commodities can fluctuate significantly due to 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 our Illinois electric delivery service business, and a FAC for our Missouri 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 that was in effect for that year, with recoveries from or refunds to customers 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 for the applicable calendar year of the monthly average 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. Fluctuations in interest rates and conditions in the capital and credit markets also affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our energy centers and 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 control to optimize our results of operations, financial position, and liquidity.

Earnings Summary

Net income attributable to Ameren Corporation was $302 million, or $1.24 per diluted share, in the third quarter of 2013, compared with net income of $374 million, or $1.54 per diluted share, in the third quarter of 2012. Net income attributable to Ameren Corporation from continuing operations was $305 million, or $1.25 per diluted share, in the third quarter of 2013, compared with net income of $309 million, or $1.28 per diluted share, in the third quarter of 2012. Net income attributable to Ameren Corporation from continuing operations increased in the third quarter of 2013 in the Ameren Illinois segment by $6 million from the prior-year period. Net income attributable to Ameren Corporation from continuing operations increased in the third quarter of 2013 in the Ameren Missouri segment by $2 million from the prior-year period. The net loss attributable to Ameren Corporation from discontinued operations was $3 million in the third quarter of 2013 as compared with net income of $65 million in the same period last year.

Net income attributable to Ameren Corporation increased to $252 million, or $1.03 per diluted share, in the first nine months of 2013, from $182 million, or $0.75 per diluted share, in the first nine months of 2012. Net income attributable to Ameren

Corporation from continuing operations decreased to $464 million, or $1.91 per diluted share, in the first nine months of 2013, from $507 million, or $2.09 per diluted share, in the first nine months of 2012. Net income attributable to Ameren Corporation from continuing operations decreased in the first nine months of 2013 in the Ameren Missouri segment by $38 million from the prior-year period. Net income attributable to Ameren Corporation from continuing operations increased in the first nine months of 2013 in the Ameren Illinois segment by $9 million from the prior-year period. The net loss attributable to Ameren Corporation from discontinued operations decreased to $212 million in the first nine months of 2013 from $325 million in the same period in 2012.

Net income from continuing operations at Ameren was unfavorably impacted in the third quarter and first nine months of 2013, compared with the same periods in 2012, by:

•

decreased electric demand resulting from summer temperatures that were cooler than last year’s warmer-than-normal temperatures, partially offset in both periods by the absence of the collar adjustment impact on Ameren Illinois earnings which came into effect with the hot summer weather in 2012, and partially offset in the nine-month period by increased natural gas demand in the first quarter of 2013 (estimated at 15 cents per share and 10 cents per share, respectively); and

•

a reduction in revenues at Ameren Missouri resulting from the Missouri Court of Appeals’ May 2013 decision, which upheld the MoPSC's April 2011 order, and a MoPSC order issued in July 2013 for the estimated obligation to refund to customers amounts associated with certain long-term partial requirements sales recognized for the period from October 1, 2009, to May 31, 2011 (1 cent per share and 7 cents per share, respectively).

In addition to these items unfavorably impacting both periods, net income from continuing operations at Ameren was unfavorably impacted in the first nine months of 2013, compared with the same period in 2012, by:


•	costs associated with the Callaway energy center's scheduled refueling and maintenance outage in the second quarter of 2013. There was no Callaway refueling and maintenance outage in 2012 (10 cents per share); and


•	the absence in 2013 of a 2012 Entergy refund not included in the FAC that reduced Ameren Missouri's purchased power expense and increased interest income. In June 2012, FERC ordered the refund from Entergy for a power purchase agreement that expired in 2009 (7 cents per share).

Net income from continuing operations at Ameren was favorably impacted in the third quarter and first nine months of 2013, compared with the same periods in 2012, by:


•	higher Ameren Missouri utility rates pursuant to an order issued by the MoPSC, which became effective in January 2013, partially offset by increased regulatory asset amortization directed by the rate order. This excludes

MEEIA impacts, which are discussed separately below (8 cents per share and 13 cents per share, respectively);

•

an increase in Ameren Illinois' electric delivery earnings under formula ratemaking. The third quarter was favorably impacted by timing differences, increased rate base and a higher allowed return on equity. The nine-month period was favorably impacted by increased rate base, a higher allowed return on equity, and lower required contributions pursuant to the IEIMA. (8 cents per share and 2 cents per share, respectively);


•	higher revenues associated with Ameren Missouri's MEEIA energy efficiency lost revenue recovery mechanism (3 cents per share and 5 cents per share, respectively), which are partially offset by lower revenues resulting from reduced demand due to energy efficiency programs; and


•	higher electric transmission rates at Ameren Illinois and ATXI (1 cent per share and 6 cents per share, respectively).

The cents per share information presented above is based on the diluted average shares outstanding in the third quarter and first nine months of 2012. There was no difference between basic and diluted shares in 2012. For further details regarding the Ameren Companies' results of operations for the third quarter and the first nine months of 2013, including explanations of Margins, Other Operations and Maintenance Expenses, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income and Expenses, Interest Charges, Income Taxes, and Loss from Discontinued Operations, Net of Tax, see the major headings below.

Below is a table of income statement components by segment for the three and nine months ended September 30, 2013, and 2012:



	Ameren Missouri			Ameren Illinois			Other / Intersegment Eliminations			Total
Three Months 2013:
Electric margin	$	820		$	336		$	1		$	1,157
Natural gas margin	13			77			(1		)	89
Other revenues	1			—			(1		)	—
Other operations and maintenance	(212		)	(166		)	(5		)	(383		)
Depreciation and amortization	(114		)	(59		)	(2		)	(175		)
Taxes other than income taxes	(91		)	(30		)	—			(121		)
Other income and (expenses)	14			1			—			15
Interest charges	(43		)	(31		)	(14		)	(88		)
Income (taxes) benefit	(149		)	(51		)	13			(187		)
Income (loss) from continuing operations	239			77			(9		)	307
Loss from discontinued operations, net of tax	—			—			(3		)	(3		)
Net income (loss)	239			77			(12		)	304
Noncontrolling interest and preferred dividends	(1		)	—			(1		)	(2		)
Net income (loss) attributable to Ameren Corporation	$	238		$	77		$	(13	)	$	302
Three Months 2012:
Electric margin	$	817		$	312		$	(4	)	$	1,125
Natural gas margin	13			77			—			90
Other revenues	—			—			—			—
Other operations and maintenance	(203		)	(159		)	—			(362		)
Depreciation and amortization	(111		)	(55		)	5			(161		)
Taxes other than income taxes	(87		)	(24		)	(3		)	(114		)
Other income and (expenses)	11			—			—			11
Interest charges	(55		)	(34		)	(10		)	(99		)
Income (taxes) benefit	(148		)	(46		)	15			(179		)
Income (loss) from continuing operations	237			71			3			311
Income from discontinued operations, net of tax	—			—			63			63
Net income	237			71			66			374
Noncontrolling interest and preferred dividends	(1		)	—			1			—
Net income attributable to Ameren Corporation	$	236		$	71		$	67		$	374
Nine Months 2013:
Electric margin	$	1,919		$	857		$	(1	)	$	2,775
Natural gas margin	58			293			(2		)	349
Other revenues	1			2			(3		)	—
Other operations and maintenance	(686		)	(538		)	(5		)	(1,229		)
Depreciation and amortization	(338		)	(182		)	(8		)	(528		)
Taxes other than income taxes	(247		)	(102		)	(5		)	(354		)
Other income and (expenses)	34			—			(1		)	33
Interest charges	(159		)	(96		)	(34		)	(289		)
Income (taxes) benefit	(217		)	(93		)	22			(288		)
Income (loss) from continuing operations	365			141			(37		)	469
Loss from discontinued operations, net of tax	—			—			(212		)	(212		)
Net income (loss)	365			141			(249		)	257
Noncontrolling interest and preferred dividends	(3		)	(2		)	—			(5		)
Net income (loss) attributable to Ameren Corporation	$	362		$	139		$	(249	)	$	252
Nine Months 2012:
Electric margin	$	1,898		$	828		$	(8	)	$	2,718
Natural gas margin	52			270			(1		)	321
Other revenues	1			—			(1		)	—
Other operations and maintenance	(611		)	(513		)	(2		)	(1,126		)
Depreciation and amortization	(328		)	(165		)	(3		)	(496		)
Taxes other than income taxes	(236		)	(94		)	(7		)	(337		)
Other income and (expenses)	37			(10		)	(2		)	25
Interest charges	(167		)	(98		)	(30		)	(295		)
Income (taxes) benefit	(243		)	(86		)	31			(298		)
Income (loss) from continuing operations	403			132			(23		)	512
Loss from discontinued operations, net of tax	—			—			(331		)	(331		)
Net income (loss)	403			132			(354		)	181
Noncontrolling interest and preferred dividends	(3		)	(2		)	6			1
Net income (loss) attributable to Ameren Corporation	$	400		$	130		$	(348	)	$	182



Three Months	Ameren Missouri			Ameren Illinois			Other^(a)			Ameren
Electric revenue change:
Effect of weather (estimate)^(b)	$	(59	)	$	(16	)	$	—		$	(75	)
Regulated rates:
Base rates (estimate)	66			52			—			118
Recovery of FAC under-recovery^(c)	22			—			—			22
Off-system and transmission services revenues (reduction in base rates)	(7		)	—			1			(6		)
FAC prudence review charge	(3		)	—			—			(3		)
MEEIA (energy efficiency)	21			—			—			21
Transmission services	(10		)	2			2			(6		)
Gross receipts tax	3			—			—			3
Bad debt, energy efficiency programs and environmental remediation cost riders	—			(3		)	—			(3		)
Illinois pass-through power supply costs	—			(128		)	—			(128		)
Sales volume (excluding the impact of abnormal weather)	(1		)	(8		)	—			(9		)
Other	(3		)	(3		)	—			(6		)
Total electric revenue change	$	29		$	(104	)	$	3		$	(72	)
Fuel and purchased power change:
Energy costs included in base rates	$	(4	)	$	—		$	—		$	(4	)
Recovery of FAC under-recovery^(c)	(22		)	—			—			(22		)
Illinois pass-through power supply costs and other	—			128			2			130
Total fuel and purchased power change	$	(26	)	$	128		$	2		$	104
Net change in electric margins	$	3		$	24		$	5		$	32
Natural gas margins change:
Energy efficiency programs and environmental remediation cost riders	$	—		$	1		$	—		$	1
Sales and other	—			(1		)	(1		)	(2		)
Net change in natural gas margins	$	—		$	—		$	(1	)	$	(1	)
Nine Months	Ameren Missouri			Ameren Illinois			Other^(a)			Ameren
Electric revenue change:
Effect of weather (estimate)^(b)	$	(53	)	$	(15	)	$	—		$	(68	)
Regulated rates:
Base rates (estimate)	149			48			—			197
Recovery of FAC under-recovery^(c)	56			—			—			56
Off-system and transmission services revenues (reduction in base rates)	9			—			—			9
FAC prudence review charge	(25		)	—			—			(25		)
MEEIA (energy efficiency)	43			—			—			43
Transmission services	(24		)	18			8			2
Gross receipts tax	9			—			—			9
Bad debt, energy efficiency programs and environmental remediation cost riders	—			(7		)	—			(7		)
Illinois pass-through power supply costs	—			(273		)	—			(273		)
Sales volume (excluding the impact of abnormal weather)	2			(11		)	—			(9		)
Other	(3		)	(4		)	(2		)	(9		)
Total electric revenue change	$	163		$	(244	)	$	6		$	(75	)
Fuel and purchased power change:
Energy costs included in base rates	$	(62	)	$	—		$	—		$	(62	)
Recovery of FAC under-recovery^(c)	(56		)	—			—			(56		)

Ameren Corporation

Ameren's electric margins increased by $32 million, or 3%, and $57 million, or 2%, for the three and nine months ended September 30, 2013, respectively, compared with the same periods in 2012. The following items had a favorable impact on Ameren's electric margins for the three and nine months ended September 30, 2013, compared with the year-ago periods:

•

Higher Ameren Missouri electric base rates effective January 2013 ($66 million and $149 million, respectively), as a result of the 2012 MoPSC electric rate order, partially offset by an increase in net energy costs ($11 million and $53 million, respectively). The increase in net energy costs are the sum of the change in energy costs included in base rates ($4 million and $62 million, respectively) and the change in off-system and transmission services revenues (-$7 million and $9 million, respectively). Transmission services revenues for 2012 were not included in the FAC ($10 million and $24 million, respectively). See below for additional details regarding the FAC.

•

Electric delivery service formula ratemaking adjustments at Ameren Illinois resulting from the annual reconciliation of the revenue requirement pursuant to the IEIMA ($52 million and $48 million, respectively). The third quarter was favorably impacted by timing differences, increased rate base, a higher allowed return on equity, and absence of the collar adjustment impact on earnings which came into effect with the hot summer weather in 2012. The nine-month period was favorably impacted by increased rate base, a higher allowed return on equity, and absence of the collar adjustment.

•

Higher revenues associated with Ameren Missouri's MEEIA energy efficiency program cost recovery mechanism ($10 million and $23 million, respectively) and lost revenue recovery mechanism ($11 million and $20 million, respectively), effective January 2013, which increased revenues by a combined $21 million and $43 million, respectively. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency program costs.


•	Excluding Ameren Missouri, higher transmission revenues at Ameren Illinois and ATXI, due to the forward-looking rate

calculations for 2013 pursuant to the 2012 FERC orders, whereas in 2012 rates were based on a historic base period ($4 million and $26 million, respectively). On January 1, 2013, Ameren Illinois and ATXI adjusted their electric transmission rates to reflect an increase in their transmission revenue requirements. The increases in Ameren Illinois' and ATXI’s transmission revenue requirements are subject to revenue requirement reconciliations.


•	Increased gross receipts taxes at Ameren Missouri, due primarily to the higher base rates ($3 million and $9 million, respectively). 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 impact on Ameren's electric margins for the three and nine months ended September 30, 2013, compared with the year-ago periods (except where a specific period is referenced):


•	Summer weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as cooling degree-days decreased 20% and 24%, respectively, which decreased revenues by $75 million and $68 million, respectively. This excludes the impact of the collar adjustment discussed above.

•

A reduction in Ameren Missouri revenues resulting from the Missouri Court of Appeals’ May 2013 decision that upheld the MoPSC's April 2011 order and a MoPSC order issued in July 2013. Ameren Missouri recorded a FAC prudence review charge for its estimated obligation to refund to its electric customers the earnings associated with sales previously recognized by Ameren Missouri during the period from October 1, 2009, to May 31, 2011 ($3 million and $25 million, respectively). See Note 3 - Rate and Regulatory Matters under Part I, Item 1, of this report for further information regarding the FAC prudence review charge.


•	Absence in 2013 of a 2012 FERC-ordered Entergy refund that reduced Ameren Missouri’s purchased power expense that was not included in the FAC, decreased margins by $24 million for the nine months ended September 30, 2013, when compared with the same period in 2012.


•	A decrease in recovery of bad debt, energy efficiency program costs and environmental remediation costs through

rate-adjustment mechanisms at Ameren Illinois ($3 million and $7 million, respectively). See Other Operations and Maintenance Expenses in this section for information on a related offsetting decrease in bad debt, energy efficiency and environmental remediation costs.


•	Excluding the estimated impact of abnormal weather, total sales volumes decreased 3% and 1%, respectively, due in part to decreased sales in the commercial and industrial sectors at Ameren Illinois ($9 million and $9 million, respectively).

Ameren Illinois' revenues associated with Illinois pass-through power supply costs decreased because of lower power prices on purchases and reduced volumes caused by customers switching to alternative retail electric suppliers. This decrease in revenues was offset by a corresponding decrease in purchased power expense ($128 million and $273 million, respectively).

Beginning in 2012, Ameren Illinois elected to participate in performance-based formula ratemaking framework pursuant to the IEIMA. The IEIMA provides for an annual reconciliation of Ameren Illinois' electric distribution revenue requirement. As of each balance sheet date, Ameren Illinois records its estimate of the electric distribution revenue impact resulting from the reconciliation of the revenue requirement necessary to reflect the actual recoverable costs incurred for that year with the revenue requirement that was in effect for that year. See Operations and Maintenance Expenses in this section for further information regarding the revenue requirement. If the current year's revenue requirement is greater than the revenue requirement customer rates were based upon, 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. If the current year's revenue requirement is less than the revenue requirement customer rates were based upon, 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. See Note 3 - 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 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 reviews. Net energy cost includes fuel (coal, coal transportation, natural gas for generation, and nuclear), certain fuel additives, emission allowances, purchased power costs, transmission costs and revenues, and MISO costs and revenues, net of off-system revenues. The MoPSC's December 2012 electric order authorized the inclusion of fuel additive costs and transmission revenues in the FAC starting in 2013. 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 under the FAC through customer rates increased $22 million and $56 million, for the three and nine months ended September 30, 2013, respectively, compared with the same periods in 2012, with corresponding offsets to fuel expense to reduce the previously recognized FAC regulatory asset.

Ameren's natural gas margins decreased by $1 million, or 1%, for the three months ended September 30, 2013, compared with the same period in 2012. However, natural gas margins increased $28 million, or 9%, for the nine months ended September 30, 2013, compared with the same period in 2012. The following items had a favorable impact on Ameren's natural gas margins for the three and nine months ended September 30, 2013, compared with the year-ago periods (except where a specific period is referenced):


•	Winter weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as heating degree-days increased 42%, which increased revenues by $14 million for the nine months ended September 30, 2013, compared with the same period in 2012.


•	An increase in recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms at Ameren Illinois ($1 million and $6 million, respectively). See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.


•	Increased gross receipts taxes, primarily at Ameren Illinois, due to higher sales as a result of colder winter weather in 2013 compared with 2012, which increased revenues by $6 million for the nine months ended September 30, 2013, compared with the same period in 2012. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.


•	Increased Ameren Illinois natural gas rates effective in late January 2012, increased revenues by $2 million for the nine months ended September 30, 2013, when compared with the same period in 2012.

Ameren’s natural gas margins were unfavorably impacted by a 4% decrease in normalized retail sales volumes, which decreased revenues by $2 million for the three months ended September 30, 2013, when compared with the same period in 2012.

Ameren Missouri

Ameren Missouri's electric margins increased by $3 million, or less than 1%, and $21 million, or 1%, for the three and nine months ended September 30, 2013, respectively, compared with the same periods in 2012. The following items had a favorable impact on Ameren Missouri's electric margins for the three and nine months ended September 30, 2013, compared with the year-ago periods (except where a specific period is referenced):

•

Higher electric base rates, effective January 2013 ($66 million and $149 million, respectively), as a result of the 2012 MoPSC electric rate order, partially offset by an increase in net energy costs ($11 million and $53 million, respectively). The increase in net energy costs are the sum of the change in energy costs included in base rates ($4 million and $62 million, respectively) and the change in off-system and transmission services revenues (-$7 million and $9 million, respectively). Transmission services revenues for 2012 were not included in the FAC ($10 million and $24 million, respectively).

•

Higher revenues associated with the MEEIA energy efficiency program cost recovery mechanism ($10 million and $23 million, respectively) and lost revenue recovery mechanism ($11 million and $20 million, respectively), effective January 2013, which increased revenues by a combined $21 million and $43 million, respectively. 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 due primarily to the higher base rates ($3 million and $9 million, respectively). 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 impact on Ameren Missouri's electric margins for the three and nine months ended September 30, 2013, compared with the year-ago periods (except where a specific period is referenced):


•	Summer weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as cooling degree-days decreased 18% and 23%, respectively, which decreased revenues by $59 million and $53 million, respectively.

•

A reduction in revenues resulting from the Missouri Court of Appeals’ May 2013 decision that upheld the MoPSC's April 2011 order and a MoPSC order issued in July 2013. Ameren Missouri recorded a FAC prudence review charge for its estimated obligation to refund to its electric customers the earnings associated with certain long-term partial requirements sales previously recognized during the period from October 1, 2009, to May 31, 2011 ($3 million and $25 million, respectively). See Note 3 - Rate and Regulatory Matters under Part I, Item 1, of this report for further information regarding the FAC prudence review charge.


•	Absence in 2013 of a 2012 FERC-ordered Entergy refund that reduced purchased power expense that was not included in the FAC, decreased margins by $24 million for the nine months ended September 30, 2013, when compared with the same period in 2012.

Ameren Missouri's natural gas margins were flat for the three months ended September 30, 2013, compared with the same period in 2012. However, natural gas margins increased $6 million, or 12%, for the nine months ended September 30, 2013, compared with the same period in 2012. The following items had a favorable impact on Ameren Missouri's natural gas margins for the nine months ended September 30, 2013, compared with the year-ago period:


•	Winter weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as heating degree-days increased 49%, which increased revenues by $3 million for the nine months ended September 30, 2013, compared with the same period in 2012.


•	Excluding the estimated impact of abnormal weather, revenues increased by $2 million, driven largely by higher natural gas transportation sales; however, total retail sales volumes decreased 3% for the nine months ended

September 30, 2013, when compared with the same period last year.


•	Increased gross receipts taxes due to higher sales as a result of colder winter weather in 2013 compared with 2012, which increased revenues by $1 million for the nine months ended September 30, 2013, when compared with the same period in 2012. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.

Ameren Illinois

Ameren Illinois has a cost recovery mechanism for power purchased on behalf of its customers. These pass-through power costs do not affect margins; however, electric revenues and offsetting purchased power expenses may fluctuate, primarily because of customers switching to or from alternative retail electric suppliers and usage. Ameren Illinois does not generate earnings based on the resale of power but rather on the delivery of energy.

Ameren Illinois' electric margins increased by $24 million, or 8%, and $29 million, or 4%, for the three and nine months ended September 30, 2013, respectively, compared with the same periods in 2012. The following items had a favorable impact on Ameren Illinois' electric margins for the three and nine months ended September 30, 2013, compared with the year-ago periods:

•

Electric delivery service formula ratemaking adjustments resulting from the annual reconciliation of the revenue requirement pursuant to the IEIMA ($52 million and $48 million, respectively). The third quarter was favorably impacted by timing differences, increased rate base, a higher allowed return on equity, and absence of the collar adjustment impact on earnings which came into effect with the hot summer weather in 2012. The nine-month period was favorably impacted by increased rate base, a higher allowed return on equity, and absence of the collar adjustment.

•

Higher transmission revenues due to the forward-looking rate calculation for 2013 pursuant to a 2012 FERC order, whereas in 2012 rates were based on a historic base period ($2 million and $18 million, respectively). On January 1, 2013, Ameren Illinois adjusted its electric transmission rates to reflect an increase in its transmission revenue requirement, which is subject to revenue requirement reconciliation.

The following items had an unfavorable impact on Ameren Illinois' electric margins for the three and nine months ended September 30, 2013, compared with the year-ago periods:


•	Summer weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as cooling degree-days decreased 20% and 23%, respectively, which decreased revenues by $16 million and $15 million, respectively. This excludes the impact of the collar adjustment discussed above.


•	A decrease in recovery of bad debt, energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms ($3 million and $7 million,

respectively). See Other Operations and Maintenance Expenses in this section for information on a related offsetting decrease in bad debt, energy efficiency and environmental remediation costs.


•	Excluding the estimated impact of abnormal weather, total retail sales volumes decreased 6% and 3%, respectively, largely due to decreased sales in the commercial and industrial sectors ($8 million and $11 million, respectively).

Ameren Illinois' natural gas margins were flat for the three months ended September 30, 2013, compared with the same period in 2012. However, natural gas margins increased $23 million, or 9%, for the nine months ended September 30, 2013, compared with the same period in 2012. The following items had a favorable impact on Ameren Illinois' natural gas margins for the three and nine months ended September 30, 2013, compared with the year-ago periods (except where a specific period is referenced):


•	Winter weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as heating degree-days increased 39%, which increased revenues by $11 million for the nine months ended September 30, 2013, when compared with the same period in 2012.


•	An increase in recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms ($1 million and $6 million, respectively). See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.


•	Increased gross receipts taxes due to higher sales as a result of colder winter weather in 2013 compared with 2012, which increased revenues by $5 million for the nine months ended September 30, 2013, compared with the same period in 2012. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.


•	Increased natural gas rates effective in late January 2012, which increased revenues by $2 million for the nine months ended September 30, 2013, when compared with the same period in 2012.

Other Operations and Maintenance Expenses

Ameren Corporation

Three months - Other operations and maintenance expenses were $21 million higher in the third quarter of 2013, as compared with the third quarter of 2012. The following items increased other operations and maintenance expenses between periods:


•	A $10 million increase in Ameren Missouri’s energy efficiency program costs due to the requirements of MEEIA, which became effective in base rates beginning in January 2013. These costs were offset by increased electric revenues recovered through customer billings, with no overall impact on net income.


•	A $10 million increase in employee benefit costs, primarily due to higher pension expense at Ameren Missouri because of a cost increase included in base rates as a result of the

2012 MoPSC electric order and higher medical expense at Ameren Illinois resulting from increased headcount.


•	A $4 million increase in non-storm-related distribution maintenance expenditures, primarily related to the timing of a circuit maintenance program at Ameren Illinois.

Other operations and maintenance expenses decreased between periods because of the absence of a charge in 2013 for a $6 million canceled project that was recorded in the third quarter of 2012 at Ameren Missouri.

Nine months - Other operations and maintenance expenses were $103 million higher in the first nine months of 2013, as compared with the first nine months of 2012. The following items increased other operations and maintenance expenses between periods:


•	A $30 million increase in plant maintenance costs, primarily due to $38 million in costs for the scheduled 2013 Callaway energy center refueling and maintenance outage as there was no outage in 2012, partially offset by an $8 million reduction in costs due to fewer major boiler outages at coal-fired energy centers.


•	A $23 million increase in Ameren Missouri’s energy efficiency program costs due to the requirements of MEEIA, which became effective in base rates beginning in January 2013.


•	A $14 million increase in labor costs, primarily because of wage increases and Ameren Illinois staff additions to comply with the requirements of the IEIMA.

•

A $12 million increase in employee benefit costs, primarily due to higher pension expense at Ameren Missouri because of a cost increase included in base rates and increased amortization of prior-year pension deferrals both as a result of the 2012 MoPSC electric order. These increased expenses were offset by increased electric revenues recovered through customer billings, with no overall impact on net income.


•	A $10 million increase in storm-related repair costs, primarily due to major storms in the second quarter of 2013. For Ameren Missouri, a portion of these costs were offset by increased electric revenues recovered through customer billings. For Ameren Illinois, these costs are recoverable under provisions of the IEIMA.


•	A $5 million increase in Ameren Illinois natural gas operations and maintenance expenses, primarily because of expenses for pipeline integrity compliance.


•	A $5 million increase in Ameren Illinois energy efficiency and environmental remediation costs. These costs were offset by increased electric and natural gas revenues recovered through customer billings, with no overall impact on net income.

Other operations and maintenance expenses decreased between periods because of the absence of a charge in 2013 for a $6 million canceled project that was recorded in 2012 at Ameren Missouri.

Variations in other operations and maintenance expenses in Ameren's business segments and for the Ameren Companies for the three and nine months ended September 30, 2013, compared

with the same periods in 2012, were as follows:

Ameren Missouri

Three months - Other operations and maintenance expenses were $9 million higher in the third quarter of 2013, as compared with the third quarter of 2012. The following items increased other operations and maintenance expenses between periods:


•	A $10 million increase in energy efficiency program costs due to the requirements of MEEIA, which became effective in rates beginning in January 2013.


•	A $5 million increase in employee benefit costs, primarily due to higher pension expense because of a cost increase included in base rates as a result of the 2012 MoPSC electric order. The increased expenses were offset by increased electric revenues recovered through customer billings, with no overall impact on net income.

Other operations and maintenance expenses decreased between periods because of the absence of a charge in 2013 for a $6 million canceled project that was recorded in the third quarter of 2012.

Nine months - Other operations and maintenance expenses were $75 million higher in the first nine months of 2013, as compared with the first nine months of 2012. The following items increased other operations and maintenance expenses between periods:


•	A $30 million increase in plant maintenance costs, primarily due to $38 million in costs for the scheduled 2013 Callaway energy center refueling and maintenance outage as there was no outage in 2012, partially offset by an $8 million reduction in costs due to fewer major boiler outages at coal-fired energy centers.


•	A $23 million increase in energy efficiency program costs due to the requirements of MEEIA, which became effective in rates beginning in January 2013.


•	A $10 million increase in employee benefit costs, primarily due to higher pension expense because of a cost increase included in base rates and increased amortization of prior-year pension deferrals both as a result of the 2012 MoPSC electric order.


•	An $8 million increase in storm-related repair costs, primarily due to major storms in the second quarter of 2013. A portion of these costs, $5 million, were offset by increased electric revenues recovered through customer billings.


•	A $5 million increase in labor costs, primarily because of wage increases.

Other operations and maintenance expenses decreased between periods because of the absence of a charge in 2013 for a $6 million canceled project that was recorded in 2012 at Ameren Missouri.

Ameren Illinois

Pursuant to the provisions of the IEIMA, recoverable electric

distribution costs incurred during the year that are not recovered through riders are included in Ameren Illinois’ revenue requirement reconciliation, which results in a corresponding adjustment to electric operating revenues, with no overall impact on net income. These recoverable electric distribution costs include other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes.

Three months - Other operations and maintenance expenses were $7 million higher in the third quarter of 2013, as compared with the third quarter of 2012. The following items increased other operations and maintenance expenses between periods:


•	A $5 million increase in non-storm-related electric distribution maintenance expenditures, primarily related to the timing of the circuit maintenance program.


•	A $4 million increase in employee benefit costs, primarily due to higher medical expense resulting from increased headcount.

Nine months - Other operations and maintenance expenses were $25 million higher in the first nine months of 2013, as compared with the first nine months of 2012. The following items increased other operations and maintenance expenses between periods:


•	An $8 million increase in labor costs, primarily because of wage increases and staff additions to comply with the requirements of the IEIMA.


•	A $5 million increase in natural gas operations and maintenance expenses, primarily because of expenses for pipeline integrity compliance.


•	A $5 million increase in energy efficiency and environmental remediation costs. These costs were offset by increased electric and natural gas revenues recovered through customer billings, with no overall impact on net income.


•	A $4 million increase in non-storm-related electric distribution maintenance expenditures, primarily related to the timing of a circuit maintenance program.


•	A $2 million increase in storm-related repair costs, primarily due to major storms in 2013.

Depreciation and Amortization

Ameren Corporation

Three and nine months - Depreciation and amortization expenses increased by $14 million in the third quarter of 2013, as compared with the third quarter of 2012, and by $32 million in the first nine months of 2013, as compared with the first nine months of 2012, due to increased expenses at Ameren Missouri and Ameren Illinois as discussed below. In addition, depreciation and amortization expenses associated with the idle Meredosia and Hutsonville energy centers, which Ameren will retain when the New AER divestiture is completed, increased by $8 million for the three and nine months ended September 30, 2013, due to the decrease in 2012 in their estimated asset retirement obligations. These increases were partially offset by decreased depreciation

and amortization expenses at Ameren Services of $2 million for the nine months ended September 30, 2013, as compared with the same prior-year period, due to the completion in early 2013 of amortization of certain software that was at the end of its estimated useful life.

Variations in depreciation and amortization expenses in Ameren's business segments and for the Ameren Companies for the three and nine months ended September 30, 2013, compared with the same periods in 2012, were as follows:

Ameren Missouri

Three months - Depreciation and amortization expenses increased by $3 million, primarily due to increased amortization expense of $2 million related to the 2012 MoPSC electric rate order resulting in higher amortization of pre-MEEIA energy efficiency program costs, which became effective in base rates in January 2013.

Nine months - Depreciation and amortization expenses increased by $10 million, primarily due to increased depreciation expense of $5 million related to electric distribution infrastructure capital additions, and due to increased amortization expense of $5 million related to the 2012 MoPSC electric rate order resulting in higher amortization of pre-MEEIA energy efficiency program costs, which were reflected in electric rates effective in January 2013.

Ameren Illinois

Three and nine months - Depreciation and amortization expenses increased by $4 million and $17 million, respectively, primarily due to new electric depreciation rates, which increased depreciation expense by $4 million and $12 million, respectively, as a result of a reduction in the useful lives of existing electric meters that are being replaced with advanced metering infrastructure pursuant to the IEIMA, and due to infrastructure additions, which increased depreciation expense by $2 million and $8 million, respectively.

Taxes Other Than Income Taxes

Ameren Corporation

Three months - Taxes other than income taxes increased by $7 million in the third quarter of 2013, as compared with the third quarter of 2012, primarily due to an increase in property taxes at Ameren Illinois and an increase in gross receipts taxes at Ameren Missouri.

Nine months - Taxes other than income taxes increased by $17 million in the first nine months of 2013, as compared with the first nine months of 2012, primarily due to an increase in gross receipts taxes at Ameren Missouri and Ameren Illinois. These increased gross receipts taxes were offset by increased gross receipts tax revenues, with no overall impact 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.

Variations in taxes other than income taxes in Ameren's business segments and for the Ameren Companies for the three and nine months ended September 30, 2013, compared with the same periods in 2012, were as follows:

Ameren Missouri

Three and nine months - Taxes other than income taxes increased by $4 million and $11 million, respectively, primarily due to an increase in gross receipts taxes as a result of increased sales.

Ameren Illinois

Three months - Taxes other than income taxes increased by $6 million, primarily due to a reduction in the electric distribution tax refund between periods.

Nine months - Taxes other than income taxes increased by $8 million, primarily due to an increase in gross receipts taxes as a result of increased natural gas sales.

Other Income and Expenses

Ameren Corporation

Three months - Other income, net of expenses, increased by $4 million in the third quarter of 2013, as compared with the third quarter of 2012, primarily due to decreased donations at Ameren Missouri.

Nine months - Other income, net of expenses, increased by $8 million in the first nine months of 2013, as compared with the first nine months of 2012, primarily because decreased donations in 2013 at Ameren Illinois more than offset decreased interest income at Ameren Missouri.

Variations in other income, net of expenses, in Ameren's business segments and for the Ameren Companies for the three and nine months ended September 30, 2013, compared with the same periods in 2012, were as follows:

Ameren Missouri

Three months - Other income, net of expenses, increased by $3 million, primarily due to decreased donations.

Nine months - Other income, net of expenses, decreased by $3 million, primarily due to a decrease in interest income resulting from the absence of a 2012 interest payment received from Entergy as part of the FERC-ordered refund related to a power purchase agreement that expired in 2009.

Ameren Illinois

Three months - Other income, net of expenses, was comparable between periods.

Nine months - Other income, net of expenses, increased by $10 million, primarily due to decreased donations because of the absence in 2013 of the one-time $7.5 million contribution to the

Illinois Science and Energy Innovation Trust pursuant to the IEIMA in connection with participation in the formula ratemaking process in 2012.

Interest Charges

Ameren Corporation

Three and nine months - Interest charges decreased by $11 million in the third quarter of 2013, as compared with the third quarter of 2012, and by $6 million in the first nine months of 2013, as compared with the first nine months of 2012, primarily because of lower interest charges at Ameren Missouri and Ameren Illinois. These decreases were partially offset by an increase at Ameren (parent) of $4 million for the three and nine months ended September 30, 2013, because of an increase in interest charges associated with uncertain tax positions.

Variations in interest charges in Ameren's business segments and for the Ameren Companies for the three and nine months ended September 30, 2013, compared with the same periods in 2012, were as follows:

Ameren Missouri

Three months - Interest charges decreased by $12 million, primarily because of a decrease in interest charges associated with uncertain tax positions and reduced interest charges due to the September 2012 repurchase of $71 million of 6.00% senior secured notes, $121 million of 6.70% senior secured notes, and $57 million of 5.10% senior secured notes, and the issuance of $485 million of 3.90% senior secured notes. See Note 1 - Summary of Significant Accounting Policies under Part I, Item 1, of this report for information regarding uncertain tax positions.

Nine months - Interest charges decreased by $8 million, primarily because of a decrease in interest charges associated with uncertain tax positions and the favorable impact of the September 2012 repurchase and issuance of senior secured notes, as discussed above. Partially offsetting the decrease was an increase in the adjustment to the allowed reimbursable rate for pre-MEEIA energy efficiency programs, which was reflected as a regulatory asset on Ameren Missouri’s balance sheet.

Ameren Illinois

Three months - Interest charges decreased by $3 million, primarily due to the August 2012 repurchase of $87 million of 9.75% senior secured notes and $194 million of 6.25% senior secured notes, and the issuance of $400 million of 2.70% senior secured notes.

Nine months - Interest charges decreased by $2 million, primarily due to the favorable impact of the August 2012 repurchase and issuance of senior secured notes, as discussed above. Partially offsetting the decrease was an increase in interest applied to the regulatory liability for the 2012 revenue requirement reconciliation pursuant to the IEIMA in connection with participation in the formula ratemaking process.

Income Taxes

The following table presents effective income tax rates for Ameren’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2013, and 2012:



	Three Months				Nine Months
	2013		2012		2013		2012
Ameren^(a)	38	%	37	%	38	%	37	%
Ameren Missouri^(a)	38	%	38	%	37	%	38	%
Ameren Illinois^(a)	40	%	39	%	40	%	39	%


(a)	The provision for income taxes was based on the current estimate of the annual effective tax rate adjusted to reflect the tax impact of items discrete to the relevant period.

Ameren Corporation

Three months - The effective tax rate was higher in the third quarter of 2013, as compared with the third quarter of 2012, primarily due to changes in reserves for uncertain tax positions and lower expected benefits from tax credits.

Nine months - The effective tax rate was higher in the first nine months of 2013, as compared with the first nine months of 2012, primarily due to changes in reserves for uncertain tax positions, along with changes to valuation allowances on deferred tax assets related to charitable contribution deductions and state tax credits that we expect we will not be able to use before the expiration of the carryforward periods.

Variations in effective tax rates in Ameren's business segments and for the Ameren Companies for the three and nine months ended September 30, 2013, compared with the same periods in 2012, were as follows:

Ameren Missouri

Three months - The effective tax rate was comparable between periods.

Nine months - The effective tax rate was lower primarily because of changes to reserves for uncertain tax positions.

Ameren Illinois

Three and nine months - The effective tax rate was higher, primarily because of an increase in state tax expense, along with the decreased impact of tax credits on higher pretax income in 2013.

Income (Loss) from Discontinued Operations, Net of Taxes

See Note 2 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for information regarding Ameren’s decision to exit the Merchant Generation business and the discontinued operations disclosures relating to that business.

Ameren’s loss from discontinued operations, net of taxes, was $3 million in the third quarter of 2013, compared with income from discontinued operations of $63 million in the same period

last year. Ameren’s loss from discontinued operations, net of taxes, decreased to $212 million for the nine months ended September 30, 2013 from $331 million in the prior-year period.

Merchant Generation's electric margins decreased by $82 million, or 55%, and $184 million, or 45%, for the three and nine months ended September 30, 2013, respectively, compared with the same periods in 2012. The following items had an unfavorable impact on Merchant Generation’s electric margins for the three and nine months ended September 30, 2013, compared with the year-ago periods (except where a specific period is referenced):


•	Lower sales prices, primarily due to the expiration of higher-priced hedges ($79 million and $205 million, respectively).


•	Increase in production volume and purchased power costs ($70 million and $143 million, respectively) driven by increased sales volumes and purchases for a large industrial customer.


•	A charge related to a sales and use tax settlement with the state of Illinois, which decreased margins by $7 million for the nine months ended September 30, 2013, compared with the same period in 2012.

The following items had a favorable impact on Merchant Generation’s electric margins for the three and nine months ended September 30, 2013, compared with the year-ago periods (except where a specific period is referenced):


•	Higher sales volumes as a result of Marketing Company’s efforts to sell power to residential and small commercial customers in Illinois and a large industrial customer ($59 million and $134 million, respectively).


•	Net unrealized MTM activity on fuel-related contracts and nonqualifying power hedges, which increased margins by $24 million for the nine months ended September 30, 2013, compared with the same period in 2012.

Other operations and maintenance expenses were $7 million lower at Merchant Generation in the third quarter of 2013, primarily due to reduced fuel additive expense. Other operations and maintenance expenses were $9 million lower at Merchant Generation in the nine months ended September 30, 2013, as plant maintenance costs were $14 million lower, primarily due to reduced fuel additive expense and fewer major boiler outages, and employee benefit costs were $12 million lower, primarily caused by EEI’s 2012 plan amendments to its management and labor union postretirement medical benefit plans, which more than offset reduced gains in property sales of $11 million in the prior year period.

Depreciation and amortization expenses decreased by $18 million and $68 million in the three and nine months ended September 30, 2013, respectively, primarily because the long-lived asset impairments recorded in the fourth quarter of 2012 reduced the carrying value of net plant assets. Additionally, effective with its conclusion that the New AER disposal group and the Elgin, Gibson City, and Grand Tower gas-fired energy centers disposal group each met the criteria for held for sale presentation, Ameren suspended recording depreciation on these

assets in March 2013.

Interest charges decreased by $5 million and $12 million in the three and nine months ended September 30, 2013, respectively, primarily because of increased capitalized interest for the Newton energy center scrubber project.

The sharp decline in the market price of power in early 2012 and the related impact on electric margins, as well as the deceleration of construction of Genco's Newton energy center scrubber project, caused Merchant Generation to evaluate, during the first quarter of 2012, whether the carrying values of its coal-fired energy centers were recoverable. AERG's Duck Creek energy center's carrying value exceeded its estimated undiscounted future cash flows. As a result, Ameren recorded a noncash pretax asset impairment charge of $628 million to reduce the carrying value of AERG's Duck Creek energy center to its estimated fair value during the first quarter of 2012. During the first quarter of 2012, there was a reduction in the income tax benefit recognized in conjunction with the Duck Creek asset impairment of $85 million. For interim reporting purposes, authoritative accounting guidance requires that tax expense (or benefit) related to ordinary income (or loss) must be computed using an estimated annual effective tax rate. In 2012, Ameren's projected annual effective tax rate of 28% was lower than the statutory rate due to the Duck Creek impairment discussed above. This reduction in the recognized tax benefit was fully reversed over the first nine months of 2012. During the third quarter of 2012, Ameren recognized an additional $45 million of income tax benefits relating to the Duck Creek asset impairment recorded in the first quarter of 2012.

LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren's rate-regulated utility operating companies are the principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail customer mix primarily of rate-regulated residential, commercial, and industrial classes and a commodity mix of natural gas and electric service provide a reasonably predictable source of cash flows for Ameren, Ameren Missouri and Ameren Illinois. In addition to using cash flows from operating activities, Ameren, Ameren Missouri and Ameren Illinois use available cash, credit agreement borrowings, commercial paper issuances, money pool borrowings, or other short-term borrowings from affiliates to support normal operations and other temporary capital requirements. Ameren, Ameren Missouri and Ameren Illinois may reduce their credit agreement or short-term borrowings with cash from operations or, at their discretion, with long-term borrowings or, in the case of Ameren Missouri and Ameren Illinois, with equity infusions from Ameren. Ameren, Ameren Missouri and Ameren Illinois expect to incur significant capital expenditures over the next five years as they comply with environmental regulations and make significant investments in their electric and natural gas utility infrastructure to support overall system reliability, achieve IEIMA performance standards, and other improvements. Ameren intends to finance those capital expenditures and investments in its rate-regulated businesses with a blend of equity and debt so that it maintains a capital

structure of approximately 50% to 55% equity, assuming constructive regulatory environments. Ameren, Ameren Missouri and Ameren Illinois plan to implement their long-term financing plans for debt, equity, or equity-linked securities to finance their operations appropriately, to fund scheduled debt maturities, and to maintain financial strength and flexibility.

The use of operating cash flows and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit as was the case at September 30, 2013, for Ameren. The working capital deficit relating to continuing operations of $209 million as of September 30, 2013, was primarily the result of Ameren’s $425 million 8.875% senior unsecured notes, Ameren Missouri’s $200 million 4.65% senior secured notes and $104 million 5.50% senior secured notes, and Ameren Illinois’ $150 million 8.875% senior secured notes, all of which will mature within the next twelve months and have been classified as “Current maturities of long-term debt” on Ameren’s consolidated balance sheet at September 30, 2013. In October 2013, $44 million of Ameren Missouri’s 1993 5.45% Series tax-exempt first mortgage bonds were redeemed at par plus accrued interest. Also, in October 2013, Ameren Missouri’s $200 million 4.65% senior secured notes matured and were retired. Ameren is currently evaluating refinancing options for the remaining notes including, in part,

through the issuance of long-term notes. With the 2012 Credit Agreements, Ameren has access to $2.1 billion of credit capacity.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 2 - Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for additional information. As a result of the IPH transaction and Ameren’s intention to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to a third-party, the Merchant Generation business was classified as discontinued operations for all periods presented in this report. While it remains a business of Ameren, the Merchant Generation segment will seek to fund its operations internally and therefore will seek not to rely on financing from Ameren or external, third-party sources. The Merchant Generation segment will seek to defer or reduce capital and operating expenses, sell certain assets, and take other actions, as necessary, to fund its operations internally while maintaining safe and reliable operations. The transaction agreement with IPH contains customary covenants of Ameren that AER will be operated in the ordinary course prior to closing. However, if Ameren does not complete its divestiture of New AER, Ameren will continue to reduce, and ultimately eliminate, the Merchant Generation segment’s reliance on Ameren’s financial support.

Cash Flows from Operating Activities

Ameren Corporation

Ameren’s cash from operating activities associated with continuing operations increased in the first nine months of 2013, compared with the first nine months of 2012. The following items contributed to the increase in cash from operating activities associated with continuing operations during the first nine months of 2013, compared with the same period in 2012:


•	The absence of $138 million in premiums paid to bondholders in 2012 for the repurchase of the tendered principal of multiple series of Ameren Missouri and Ameren Illinois long-term debt notes.


•	An $89 million increase due to the cash flows associated with Ameren Missouri’s under-recovered FAC costs. Recoveries outpaced deferrals in 2013 by $36 million, while deferrals and refunds outpaced recoveries in 2012 by $53 million.


•	A $75 million increase due to changes in coal inventory levels at Ameren Missouri. During 2013, coal inventory levels were $47 million lower than year end because of delivery disruptions due to flooding, while in 2012, coal inventory levels increased $28 million primarily due to additional tons held in inventory because generation levels were below expected levels due to market conditions.


•	A $30 million increase in natural gas commodity over-recovered costs under the PGAs, primarily related to Ameren Illinois.


•	The absence of $25 million in severance payments made in 2012 as a result of the voluntary separation offers extended to Ameren Missouri employees in the fourth quarter of 2011.


•	A $22 million decrease in natural gas held in storage due to the changes in the market price for natural gas over the comparable periods.


•	Electric and natural gas margins, as discussed in Results of Operations, increased by $17 million, excluding impacts from the noncash IEIMA revenue requirement reconciliation adjustment and the May 2013 court order FAC prudence

review charge. See Note 3 - Rate and Regulatory Matters under Part I, Item 1, of this report for further information.


•	A $19 million decrease in interest payments, primarily due to 2012 refinancing activity and timing of payments on Ameren Missouri and Ameren Illinois senior secured notes.


•	A net $13 million decrease in collateral posted with counterparties primarily due to changes in the market prices of power and natural gas and in contracted commodity volumes at Ameren Illinois as well as 2013 credit rating upgrades.


•	A $13 million decrease in energy efficiency expenditures for Ameren Illinois customer programs that are recovered through customer billings over time.


•	A one-time $7.5 million contribution, in 2012, by Ameren Illinois to the Illinois Science and Energy Innovation Trust as required by the IEIMA.

The following items partially offset the increase in Ameren's cash from operating activities during the first nine months of 2013 compared with the same period in 2012:


•	A $98 million increase in income tax payments. As discussed below, income tax payments at Ameren Missouri increased $58 million while income tax refunds at Ameren Illinois decreased $40 million. Considering both Ameren's continuing and discontinued operations, Ameren has made minimal federal income tax payments in 2013.


•	A $60 million increase in pension and postretirement benefit plan contributions primarily caused by the timing of payments in 2013 compared with 2012.


•	A $33 million increase in energy efficiency expenditures for Ameren Missouri customer programs that are recovered through customer billings over time.


•	A $33 million increase in accounts receivable balances to reflect the timing of revenues earned, but not yet collected, from customers.


•	A $30 million increase in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center, partially offset by unpaid liabilities as of December 31, 2011, pertaining to the fall 2011 outage that were paid in 2012. There was no refueling and maintenance outage in 2012.


•	A $21 million increase at Ameren Illinois associated with deferred recoveries of purchased power and transmission delivery pass-through costs.


•	A $20 million increase in property tax payments at Ameren Missouri caused by the timing of payments and higher assessed property tax values.


•	The absence in 2013 of court registry receipts and payments. In 2012, Ameren Missouri received $19 million from the Circuit Court of Stoddard County's registry, net of payments into that registry, as a result of a Missouri Court of Appeal ruling upholding the MoPSC's January 2009 electric rate order.


•	A $10 million increase in major storm restoration costs.

Ameren’s cash from operating activities associated with discontinued operations decreased in the first nine months of 2013, compared with the first nine months of 2012, primarily

attributable to a $208 million decrease in electric margins, excluding impacts of noncash unrealized MTM activity, as discussed in Results of Operations, partially offset by a $93 million increase in income tax refunds in 2013 due to a reduction in pretax book income partially offset by a reduction in accelerated depreciation deductions. Ameren’s discontinued operations received these income tax refunds through the tax allocation agreement with Ameren’s continuing operations entities.

Ameren Missouri

Ameren Missouri’s cash from operating activities increased in the first nine months of 2013, compared with the first nine months of 2012. The following items contributed to the increase in cash from operating activities during the first nine months of 2013, compared with the same period in 2012:


•	An $89 million increase due to the cash flows associated with under-recovered FAC costs. Recoveries outpaced deferrals in 2013 by $36 million, while deferrals and refunds outpaced recoveries in 2012 by $53 million.


•	A $75 million increase due to changes in coal inventory levels. During 2013, coal inventory levels were $47 million lower than year end because of delivery disruptions due to flooding, while in 2012, coal inventory levels increased $28 million primarily due to additional tons held in inventory because generation levels were below expected levels due to market conditions.


•	The absence of $62 million in premiums paid to bondholders in 2012 for the repurchase of the tendered principal of multiple series of long-term debt notes.


•	Electric and natural gas margins, as discussed in Results of Operations, increased by $52 million, excluding the impact from the noncash charge recorded in the first nine months of 2013 associated with the FAC prudence review charge.


•	The absence of $25 million in severance payments made in 2012 as a result of the voluntary separation offers extended to employees in the fourth quarter of 2011.


•	A $10 million decrease in interest payments, primarily due to 2012 refinancing activity and timing of payments on senior secured notes.

The following items partially offset the increase in Ameren Missouri’s cash from operating activities during the first nine months of 2013, compared with the same period in 2012:


•	A $58 million increase in income tax payments resulting primarily from a reduction in accelerated depreciation deductions.


•	A $43 million increase in accounts receivable balances to reflect the timing of revenues earned, but not yet collected, from customers.


•	A $33 million increase in energy efficiency expenditures for customer programs that are recovered through customer billings over time.


•	A $30 million increase in pension and postretirement benefit plan contributions primarily caused by the timing of payments in 2013 compared with 2012.


•	A $30 million increase in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center, partially offset by unpaid liabilities as of December 31, 2011, pertaining to the fall 2011 outage, that were paid in 2012. There was no refueling and maintenance outage in 2012.


•	A $20 million increase in property tax payments caused by the timing of payments and higher assessed property tax values.


•	The absence in 2013 of court registry receipts and payments. In 2012, Ameren Missouri received $19 million from the Circuit Court of Stoddard County's registry, net of payments into that registry, as a result of a Missouri Court of Appeal ruling upholding the MoPSC's January 2009 electric rate order.


•	An $8 million increase in major storm restoration costs.

Ameren Illinois

Ameren Illinois’ cash from operating activities increased in the first nine months of 2013, compared with the first nine months of 2012. The following items contributed to the increase in cash from operating activities during the first nine months of 2013, compared with the same period in 2012:


•	The absence of $76 million in premiums paid to bondholders in 2012 for the repurchase of the tendered principal of multiple series of long-term debt notes.


•	A $22 million increase in natural gas commodity over-recovered costs under the PGA.


•	A $20 million decrease in accounts receivable balances to reflect the timing of revenues earned, but not yet collected, from customers.


•	An $18 million decrease in natural gas held in storage due to the changes in the market price for natural gas over the comparable periods.


•	A $13 million decrease in energy efficiency expenditures for customer programs that are recovered through customer billings over time.


•	A $12 million decrease in interest payments, primarily due to 2012 refinancing activity and timing of payments on senior secured notes.


•	A net $11 million decrease in collateral posted with counterparties primarily due to changes in the market prices of power and natural gas and in contracted commodity volumes as well as 2013 credit rating upgrades.


•	A one-time $7.5 million contribution, in 2012, to the Illinois Science and Energy Innovation Trust as required by the IEIMA.

The following items partially offset the increase in Ameren Illinois’ cash from operating activities during the first nine months of 2013, compared with the same period in 2012:


•	Electric and natural gas margins, as discussed in Results of Operations, decreased by $41 million, excluding the impact from the noncash IEIMA revenue requirement reconciliation adjustment.


•	A $40 million decrease in income tax refunds resulting primarily from a reduction in accelerated depreciation deductions.


•	A $21 million increase associated with deferred recoveries of purchased power and transmission delivery pass-through costs.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities associated with continuing operations in the first nine months of 2013 increased compared to the same period in 2012. Capital expenditures increased $181 million as a result of activity at the registrant subsidiaries discussed below as well as increased transmission expenditures at ATXI related to the Illinois Rivers project. This increase was partially offset by a $22 million decrease in nuclear fuel expenditures due to timing of purchases.

Cash flows used in investing activities associated with Ameren’s discontinued operations decreased during the first nine months of 2013, compared with the same period in 2012, primarily due to reduced capital expenditures in 2013 as a result of the deceleration of construction of scrubbers at the Newton energy centers partially offset by the absence in 2013 of property sale proceeds of $16 million received from the 2012 sale of the Medina Valley energy center’s net property and plant.

Ameren Missouri’s cash used in investing activities decreased during the first nine months of 2013, compared with the same period in 2012. Cash flows used in investing activities decreased as a result of money pool advance repayments of $24 million and a $22 million decrease in nuclear fuel expenditures due to timing of purchases partially offset by a $35 million increase in capital expenditures. Capital expenditures increased primarily because of increases in maintenance and reliability projects and storm restoration costs, which more than offset reduced expenditures for energy center projects.

Ameren Illinois’ cash used in investing activities increased during the first nine months of 2013, compared with the same period in 2012, primarily due to an increase in capital expenditures of $153 million for electric transmission to address load growth and reliability requirements, as well as increased capital expenditures for the modernization of its electric distribution system under the IEIMA.

See Note 10 - Commitments and Contingencies under Part I, Item 1, of this report for a discussion of future environmental capital expenditure estimates.

We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other things. 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 investment could vary due to changes in expected

capacity, the condition of transmission and distribution systems, and the ability and willingness to pursue transmission investments, among other things. Any changes that we may plan to make for future generation, transmission or distribution needs could result in significant capital expenditures or losses being incurred, which could be material.

Cash Flows from Financing Activities

Ameren’s net cash used in financing activities associated with continuing operations decreased during the nine months ended September 30, 2013, compared with the same period in 2012. In the first nine months of 2013, Ameren had limited debt financing activity, while in 2012, Ameren subsidiaries issued $885 million in senior debt and used the proceeds, together with other available cash, to repurchase and repay existing long-term indebtedness of $754 million and pay related premiums. Additionally, in 2012, Ameren repaid $143 million of its net short-term debt. Ameren declared common stock dividends totaling $291 million in the first nine months of both 2013 and 2012. Dividends paid on common stock increased $7 million in 2013, as compared with 2012, as a result of 2012 non-cash financing activity of $7 million due to the timing of DRPlus common stock dividend funding.

Ameren Missouri’s net cash used in financing activities increased during the nine months ended September 30, 2013, compared with the same period in 2012. Common stock dividends increased $20 million in 2013 compared to 2012. Ameren Missouri was able to meet its working capital requirements and investing requirements without utilizing financing during the first nine months of 2013, while in 2012,

Ameren Missouri issued $485 million of 3.90% senior secured notes and used the proceeds, together with other available cash, to repurchase and repay existing long-term indebtedness of $422 million and pay related premiums.

Ameren Illinois’ net cash used in financing activities decreased during the nine months ended September 30, 2013, compared with the same period in 2012. Ameren Illinois had minimal debt financing activity in 2013, while in 2012, Ameren Illinois issued $400 million of 2.70% senior secured notes and used the proceeds, together with other available cash, to repurchase and repay existing long-term indebtedness of $332 million and pay related premiums. During 2013, common stock dividends decreased by $87 million.

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, and drawings under committed bank credit agreements or commercial paper issuances. See Note 4 - 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 utility and non-state-regulated subsidiary money pool arrangements.

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

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

At September 30, 2013, 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 our operating cash flows. 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.

Discontinued Operations

AER’s operating results and operating cash flows are significantly affected by changes in market prices for power, which have significantly decreased over the past few years. Under the provisions of its indenture, described in Note 2 - Divestiture Transactions and Discontinued Operations, under Part I, Item 1, of this report, Genco may not borrow additional funds from external, third-party sources if its interest coverage ratio is less than a specified minimum or if its debt-to-capital ratio is greater than a specified maximum. Beginning in the first quarter of 2013, Genco’s interest coverage ratio fell to a level less than the specified minimum level required for external borrowings, and Genco expects the ratio to remain less than this minimum level through at least 2015. As a result, Genco’s ability to borrow additional funds from external, third-party sources is restricted. Genco’s indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren’s control, and if a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time. While it remains a business of Ameren, the Merchant Generation segment, including Genco, seeks to fund its operations internally and, therefore, seeks not to rely on financing from Ameren or external, third-party sources.

Should a financing need arise, Genco's sources of liquidity include available cash on hand, a return of money pool advances, and money pool borrowings at the discretion of Ameren. On March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which was subject to FERC approval. On October 11, 2013, Ameren received FERC approval for the divestiture of New AER to IPH and Genco’s sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. Immediately after receipt of FERC approval, Genco completed its sale of these gas-fired energy centers to Medina Valley and received additional cash proceeds of $37.5 million. Medina Valley has entered into an agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. Ameren expects this third-party sale of these gas-fired energy centers to close by the end of 2013, subject to FERC and other regulatory approvals. These put option proceeds, along with cash on hand and the return of money pool advances, are Genco's primary sources of liquidity. Based on current projections, excluding the amount received related to the put option, Genco expects operating cash flows to approximate nonoperating cash flow requirements in 2013.

Dividends

Ameren declared, and paid to its stockholders, common stock dividends totaling $291 million, or $1.20 per share during the first nine months of 2013 (2012 - $291 million declared or $1.20 per share). On October 11, 2013, Ameren’s board of directors declared a quarterly common stock dividend of 40 cents per share payable on December 31, 2013, to stockholders of record on December 11, 2013.

Genco’s indenture includes restrictions that can prohibit it from making dividend payments on its common stock. Specifically, Genco cannot pay dividends on its common stock unless the company’s actual interest coverage ratio for the most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on projections as of September 30, 2013, of Genco’s operating results and cash flows in 2013 and 2014, we do not expect that Genco will achieve the minimum interest coverage ratio necessary to pay dividends on its common stock for each of the subsequent four six-month periods ending March 31, 2014, September 30, 2014, March 31, 2015, or September 30, 2015. As a result, Genco was restricted from paying dividends as of September 30, 2013, and we expect Genco to be unable to pay dividends on its common stock through at least September 30, 2016.

See Note 2 - Divestiture Transactions and Discontinued Operations 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 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, 2013, none of these circumstances existed at Ameren, Ameren Missouri and Ameren Illinois and, as a result, these companies were not restricted from paying dividends.

The following table presents common stock dividends 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, 2013, and 2012:



	Nine Months
	2013		2012
Ameren Missouri	$	320	$	300
Ameren Illinois	45		132
Dividends paid by Ameren	291		284

Contractual Obligations

For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7, and Note 15 - Commitments and Contingencies under Part II, Item 8, of the Form 10-K, and Other Obligations in Note 10 - Commitments and Contingencies under Part I, Item 1, of this report. See Note 12 - Retirement Benefits under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan.

At September 30, 2013, total other obligations related to the procurement of 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 $6,815 million, $4,936 million, and $1,853 million respectively. Total unrecognized tax benefits (detriments) at September 30, 2013, which were not included in the previous totals, for Ameren, Ameren Missouri, and Ameren Illinois were $86 million, $27 million, and $(2) million, respectively.

Off-Balance-Sheet Arrangements

At September 30, 2013, none of the Ameren Companies had 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 9 - Related Party Transactions under Part I, Item 1, of this report for Ameren (parent) guarantees on behalf of its subsidiaries.

Credit Ratings

The credit ratings of the Ameren Companies affect our liquidity, our access to the capital markets and credit markets, our cost of borrowing under our 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	Baa3	BBB	BBB
Senior unsecured debt	Baa3	BBB-	BBB
Commercial paper	P-3	A-2	F2
Ameren Missouri:
Issuer/corporate credit rating	Baa2	BBB	BBB+
Secured debt	A3	A	A
Ameren Illinois:
Issuer/corporate credit rating	Baa2	BBB	BBB-
Secured debt	A3	A	BBB+
Senior unsecured debt	Baa2	BBB	BBB

The cost of borrowing under our credit facilities can also increase or decrease depending upon the credit ratings of the borrower. 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 changes in credit ratings relating to Ameren’s continuing operations may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power, and natural gas supply, among other things, resulting in a negative impact on earnings. Cash collateral postings and prepayments with external parties, including postings related to exchange-traded contracts, at September 30, 2013, were $37 million, $13 million, and $24 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively. Cash collateral posted by external counterparties with Ameren and Ameren Illinois was $2 million and $2 million, respectively, at September 30, 2013. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at September 30, 2013, 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 $133 million, $63 million, and $70 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments at current credit ratings. If market prices were 15% higher than September 30, 2013, 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. If market prices were 15% lower than September 30, 2013, 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 approximately $17 million, $4 million, and $13 million, respectively.

See Note 2 - Divestiture Transactions and Discontinued Operations under Part I, Item I, of this report for information regarding Ameren's transaction agreement to divest New AER to IPH. Upon the divestiture of New AER to IPH, the transaction agreement between Ameren and IPH requires Ameren to maintain its financial obligations with respect to all credit support provided to New AER for all transactions entered into prior to the closing of such divestiture for up to 24 months after the closing. The permitted forms of credit support for each counterparty agreement could include one or more of the following: cash, a letter of credit, a parent company guarantee, or other credit support alternatives. Ameren's exposure related to the continuation of credit support provided to New AER after the divestiture closing date is dependent upon the transactions and counterparty agreements that AER and its subsidiaries have in effect as of the divestiture closing date. 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 will

be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH's indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions). See Note 9 - Related Party Transactions under Part I, Item 1, of this report for information regarding Ameren (parent) guarantees.

Cash collateral postings and prepayments by AER and its subsidiaries with external parties, including postings related to exchange-traded contracts, at September 30, 2013, were $27 million. There was no cash collateral posted by external counterparties with AER and its subsidiaries at September 30, 2013. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at Ameren at September 30, 2013, could have resulted in Ameren being required to post additional collateral or other assurances for certain trade obligations of AER and its subsidiaries amounting to $73 million. Changes in commodity prices could trigger additional collateral postings and prepayments for AER and its subsidiaries based on Ameren’s current credit ratings. If market prices were 15% higher than September 30, 2013, levels in the next 12 months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren could be required to post additional collateral or other assurances for certain trade obligations of New AER up to $113 million. If market prices were 15% lower than September 30, 2013, levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren could be required to post additional collateral or other assurances for certain trade obligations of New AER up to $71 million.

OUTLOOK

Ameren seeks to earn competitive returns on its investments in its businesses. Ameren Missouri and Ameren Illinois are seeking to improve their regulatory frameworks and cost recovery mechanisms and simultaneously pursuing constructive regulatory outcomes within existing frameworks. Ameren Missouri and Ameren Illinois are seeking to align their overall spending, both operating and capital, with economic conditions and cash flows provided by their regulators. Consequently, Ameren's rate-regulated businesses are focused on minimizing the gap between allowed and earned returns on equity. On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. This divestiture will position Ameren to focus exclusively on its rate-regulated electric, natural gas and transmission operations, clarifying Ameren’s strategic direction. Ameren intends to allocate its capital resources to those business opportunities which offer the most attractive risk-adjusted return potential.

Below are some key trends, events, and uncertainties that are reasonably likely to affect the Ameren Companies' results of operations, financial condition, or liquidity, as well as their ability to achieve strategic and financial objectives, for 2013 and beyond.

Rate-Regulated Operations


•	Ameren's strategy for earning competitive returns on its rate-regulated 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.

•

In July 2013, Illinois enacted a law called the Natural Gas Consumer, Safety and Reliability Act, that enables Illinois natural gas utilities to accelerate modernization of the state’s natural gas infrastructure and provide additional ICC oversight of natural gas utility performance. The law allows natural gas utilities the option to file, and requires the ICC to approve, a rate rider mechanism to provide for recovery of costs associated with certain categories of investment to improve the safety and reliability of the state’s natural gas infrastructure. Ameren Illinois expects to begin participation in this regulatory framework in 2014. Ameren Illinois anticipates it will increase its natural gas capital expenditures when it elects to participate in the new law’s regulatory framework.

•

In December 2012, the ICC issued an order with respect to Ameren Illinois' update IEIMA filing approving an electric delivery service revenue requirement that was a $70 million decrease from the requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The new rates became effective on January 1, 2013. These rates will impact Ameren Illinois’ cash flows during 2013, but not its operating revenues, which are instead impacted by the IEIMA’s 2013 revenue requirement reconciliation discussed below.

•

The IEIMA provides for an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for that year. Consequently, Ameren Illinois' 2013 electric delivery service revenues will be based on its 2013 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. The 2013 revenue requirement is expected to be higher than the 2012 revenue requirement due to expected increases in recoverable costs and rate base growth, even though the amount added to the monthly average yields of the 30-year United States treasury bonds decreased to 580 basis points in 2013 from 590 basis points in 2012.

•

In April 2013, Ameren Illinois filed its annual electric delivery formula rate update with the ICC based on 2012 recoverable costs and expected net plant additions for 2013. The update filing was revised based on the enactment of May 2013 amendments to the IEIMA. Pending ICC approval, the update filing, as filed by Ameren Illinois, would result in a $22 million decrease in Ameren Illinois’ electric delivery revenue requirement beginning in January 2014. The ICC staff has submitted testimony recommending a $42 million decrease in Ameren Illinois' electric delivery revenue requirement. An ICC decision with respect to the revised update filing is required in December 2013 and will establish rates for all of 2014. These rates will impact Ameren Illinois’

cash flows during 2014, but not its operating revenues, which will instead be impacted by the IEIMA’s 2014 revenue requirement reconciliation.

•

In January 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service. The current request, as revised in August 2013, seeks to increase annual revenues for natural gas delivery service by $47 million. The ICC staff is recommending a $28 million increase in Ameren Illinois’ annual revenues for natural gas service. In an attempt to reduce regulatory lag, Ameren Illinois used a future test year, 2014, in this proceeding. A decision in this proceeding is required in December 2013.

•

In December 2012, the MoPSC issued an order approving an increase in Ameren Missouri’s in annual electric revenues of $260 million, including $84 million related to an anticipated increase in normalized net energy costs above the net energy costs included in base rates previously authorized by the MoPSC in its 2011 electric rate order. The annual increase also includes $80 million for recovery of the costs associated with energy efficiency programs under the MEEIA. The remaining annual increase of $96 million approved by the MoPSC was for energy infrastructure investments and other non-energy costs, including $10 million for increased pension and other post-employment benefit costs and $6 million for increased amortization of regulatory assets. The new rates became effective on January 2, 2013.


•	The MoPSC's December 2012 electric rate order approved Ameren Missouri's implementation of MEEIA megawatthour savings targets, energy efficiency programs, and associated cost recovery mechanisms and incentive awards. Beginning in 2013, Ameren Missouri will invest $147 million over three years for energy efficiency programs.

•

As they continue to experience cost increases and 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 expects to file an electric rate case in the second half of 2014. Ameren Missouri and Ameren Illinois will also seek legislative solutions to address cost recovery pressures. These pressures include a weak economy, customer conservation efforts, the impacts of energy efficiency programs, increased investments and expected future investments for environmental compliance, system reliability improvements, and new baseload 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, higher property and income taxes, and higher insurance premiums as a result of insurance market conditions and industry loss experience, among other things.


•	Ameren and Ameren Missouri are pursuing recovery from insurers, through litigation, for reimbursement of unpaid liability insurance claims for a December 2005 breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center.

•

Ameren Missouri completed a scheduled refueling and maintenance outage at its Callaway energy center during the second quarter of 2013. The next scheduled refueling and maintenance outage will be in the fall of 2014. During a scheduled outage, which occurs every 18 months, maintenance expense will increase. 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 will decrease versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC, resulting in limited impact to earnings. Electric operating revenues in 2013 will not fully offset the additional maintenance costs incurred during the 2013 outage, because revenues relating to the additional maintenance costs are recovered over 18 months.

•

Ameren Missouri continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. Environmental regulations, as well as future initiatives related to greenhouse gas emissions, could result in significant increases in capital expenditures and operating costs that could be prohibitive at some of Ameren Missouri's coal-fired energy centers, particularly at its Meramec energy center. The expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures for their continued operation.

•

Ameren continues to pursue its plans to invest in electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The first project, Illinois Rivers, involves the building of a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. In August 2013, the ICC granted a certificate of public convenience and necessity and approved seven of nine sections of the route and three of the proposed nine substations for the project. In October 2013, the ICC granted ATXI’s request for a rehearing to consider additional evidence regarding the unapproved portions of the project. An order on rehearing is expected in March 2014. Right-of-way acquisitions for the approved portions of the project have begun with a full range of construction activities to begin in 2014. 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 in 2019. The Spoon River project in northwest Illinois and the Mark Twain project in northeast Missouri are the other two projects approved by MISO in its transmission expansion plan. These two projects are expected to be completed in 2018. The total investment in these three projects is expected to be more than $1.3 billion through 2019. FERC has approved transmission rate incentives for the three MISO-approved projects as well as for the Big Muddy River project. The Big Muddy River project, located primarily in southern Illinois, may be evaluated for inclusion in MISO's future transmission expansion plans. Separate from the ATXI projects discussed above, Ameren Illinois expects to invest approximately $1 billion in electric transmission assets over the next five years to address load growth and reliability requirements.

•

In November 2012, FERC approved a forward-looking rate calculation with an annual revenue requirement reconciliation for Ameren Illinois' electric transmission business. Based on its forward-looking rate calculation, on January 1, 2013, Ameren Illinois adjusted its electric transmission rates to reflect an increase in its transmission revenue requirement of $29 million. The increase in Ameren Illinois' transmission revenue requirement is subject to an annual revenue requirement reconciliation, which could result in an adjustment to revenues based on the actual revenue requirement in 2013.

•

For additional information regarding recent rate orders and related appeals, pending requests filed with state and federal regulatory commissions, Taum Sauk matters, and separate FERC orders impacting Ameren Missouri and Ameren Illinois, see Note 3 - Rate and Regulatory Matters, and Note 10 - Commitments and Contingencies 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.

Discontinued Operations

•

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 2 - Divestiture Transactions and Discontinued Operations under Part I, Item 1 of this report for additional information. Under the terms of the transaction agreement, Ameren is required to operate its Merchant Generation business in the ordinary course through the transaction closing date, which is expected to occur by the end of 2013. However, if Ameren does not complete its divestiture of New AER, Ameren will continue to reduce, and ultimately eliminate, the Merchant Generation segment’s reliance on Ameren’s financial support.

•

Completion of the divestiture of New AER to IPH requires FERC and FCC approvals. In October 2013, Ameren received FERC approval for the divestiture of New AER to IPH. The FCC approval was received in August 2013. Separately, as a condition to IPH’s obligation to complete the acquisition of New AER, the Illinois Pollution Control Board must approve the transfer to IPH of, or otherwise approve a variance in favor of IPH on the same material terms as, AER’s variance of the Illinois MPS. In May 2013, AER and IPH filed a transfer request with the Illinois Pollution Control Board, which was subsequently denied by the board on procedural grounds. On July 22, 2013, IPH, AER and Medina Valley, as current and future owners of the coal-fired energy centers, filed a request for a variance with the Illinois Pollution Control Board seeking materially the same relief as the existing AER variance. The Illinois Pollution Control Board has until late November 2013 to issue a decision.

•

Immediately following receipt of FERC approval on October 11, 2013, Genco completed the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. Medina Valley has entered into an agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. Ameren expects the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy

centers to Rockland Capital, which is also subject to FERC and other regulatory approvals, will be completed by the end of 2013.


•	Effective with its conclusion that the New AER disposal group and the Elgin, Gibson City, and Grand Tower gas-fired energy centers disposal group each met the criteria for discontinued operations presentation, Ameren suspended recording depreciation on these assets in March 2013.


•	Ameren’s divestiture of New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers may result in long-lived asset impairments, disposal-related losses, contingencies, reductions of existing deferred tax assets, and other consequences that are currently unknown.

•

Based on current projections for 2013, excluding the put option receipts, AER expects its operating cash flows to approximate its nonoperating cash flow requirements in 2013. Included in this 2013 projection, AER expects to receive income tax benefits through the tax allocation agreement with Ameren and its non-AER affiliates of $80 million. These estimates may change significantly depending on the taxable income or loss of Ameren and each of its subsidiaries and also assume Ameren's continued ownership of AER through 2013.

•

In 2012, Marketing Company filed a notice with MISO of its intent to cease operations for one of the three units at AERG's E.D. Edwards energy center. MISO determined that AERG’s operation of that unit was required for system reliability purposes. This designation changes the pricing structure MISO uses to compensate Marketing Company for the operation of that one unit at the E.D. Edwards energy center. MISO and Marketing Company disagree on the level of revenue required to continue to have the unit available for reliability purposes. Ameren will not recognize any revenue related to this reliability contract for the E.D. Edwards unit until FERC rules on the appropriate compensation level. Depending on MISO’s reliability requirements, this rate structure could continue through 2016, although MISO could notify Marketing Company that it no longer needs the E.D. Edwards unit for reliability purposes and terminate the agreement after a 90-day notification. In July 2013, AERG submitted a series of filings with FERC requesting cost recovery, including depreciation expense, return on rate base costs, and associated taxes, to be included in the revenue requirement to continue to make the E.D. Edwards unit available for reliability purposes. In September 2013, MISO notified Marketing Company that this unit at the E.D. Edwards energy center would continue to be required for system reliability purposes through 2014. If Ameren’s ownership of AER continues through 2013, Ameren estimates it could record revenues of between $9 million and $22 million as a result of this reliability contract. Ameren will recover these revenues when they become probable, which may be after 2013.


•	The Merchant Generation segment expects to have available generation from its coal-fired energy centers of 31 million megawatthours in any given year. However, based on currently expected power prices, the Merchant Generation segment expects to generate approximately 27 million megawatthours in 2013, with approximately 95% of

this generation expected to be from coal-fired energy centers.

•

Power prices in the Midwest affect the amount of revenues and cash flows the Merchant Generation segment can realize by marketing power into the wholesale and retail markets. The Merchant Generation segment is adversely affected by the declining market price of power for any unhedged generation. Market prices for power have decreased over the past several years. Any unhedged forecasted generation will be exposed to market prices at the time of sale.


•	As of September 30, 2013, Marketing Company had sold forward approximately 28 million megawatthours for 2013, at an average price of $36 per megawatthour. Megawatthours sold forward in excess of Merchant Generation’s actual generation will be purchased from the market as needed.


•	As of September 30, 2013, for 2013, Merchant Generation had hedged fuel costs for approximately 26 million megawatthours of coal and up to 26 million megawatthours of base transportation at about $23 per megawatthour.

•

Upon the divestiture of New AER, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture and provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. See Note 9 - Related Party Transactions under Part I, Item 1, of this report for additional information.

•

Ameren anticipates the reduction in employees caused by the divestiture of New AER will result in a curtailment in its pension and postretirement benefit plans. Ameren anticipates the curtailment will result in a gain to reflect the removal of AER active employees who are not yet eligible to retire. The previously accrued liability for AER employees will remain in Ameren's pension and postretirement benefit plans; however, no additional benefits will be earned after closing.

Liquidity and Capital Resources


•	The Ameren Companies seek to maintain access to the capital markets at commercially attractive rates in order to fund their businesses. The Ameren Companies seek to enhance regulatory frameworks and returns in order to improve cash flows, credit metrics, and related access to capital for Ameren's rate-regulated businesses.

•

The use of continuing operating cash flows and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit as was the case at September 30, 2013, for Ameren. The working capital deficit of $209 million as of September 30, 2013, was primarily the result of current maturities of long-term debt, specifically Ameren’s $425 million 8.875% senior unsecured notes, Ameren Missouri’s $200 million 4.65% senior secured notes and $104 million 5.50% senior secured notes, and Ameren Illinois’ $150 million 8.875% senior secured notes, all of which will mature within the next twelve months. In October 2013, $44 million of Ameren

Missouri’s 1993 5.45% Series tax-exempt first mortgage bonds were redeemed at par plus accrued interest. Also, in October 2013, Ameren Missouri’s $200 million 4.65% senior secured notes matured and were retired. Ameren is currently evaluating refinancing options for the remaining notes including, in part, through the issuance of long-term notes. Ameren anticipates that it will be able to reduce its parent company interest costs by refinancing its senior unsecured notes in 2014. Under the 2012 Credit Agreements, Ameren has access to $2.1 billion of credit capacity.

•

As of September 30, 2013, Ameren had $330 million in federal income tax net operating loss carryforwards (Ameren Missouri - $55 million and Ameren Illinois - $170 million) and $90 million in federal income tax credit carryforwards (Ameren Missouri - $12 million and Ameren Illinois - $- million). These federal income tax net operating loss carryforwards have been reduced by $80 million to reflect the reduction in net operating loss carryforwards that Ameren expects to utilize in 2013, as discussed in a separate bullet below. Consistent with the tax allocation agreement, these carryforwards are expected to partially offset 2013 income tax liabilities for Ameren Missouri, and into 2015 for Ameren and Ameren Illinois. These amounts exclude any additional net operating losses that will be generated by the New AER divestiture transaction. The tax benefits from these losses are currently recorded as a deferred tax asset on Ameren's balance sheet.

•

In December 2011, the Internal Revenue Service issued new guidance on the treatment of amounts paid to acquire, produce or improve tangible property and dispositions of such property with respect to electric transmission, distribution, and generation assets as well as natural gas transmission and distribution assets. Final regulations related to this guidance were issued in September 2013. These new rules are required to be implemented no later than January 1, 2014. Based on a preliminary evaluation of the new guidance, Ameren expects to utilize $40 million in federal income tax net operating loss carryforwards to offset tax liabilities related to the prescribed Internal Revenue Service accounting method change that we expect to file in 2014 in connection with this new guidance.

•

In April 2013, the Internal Revenue Service issued new guidance defining when expenditures to maintain, replace or improve steam or electric power generation property must be capitalized. This April 2013 guidance is expected to change how Ameren determines whether expenditures related to plant and equipment are deducted as repairs or capitalized for income tax purposes. Based on a preliminary evaluation of the new guidance, Ameren expects to utilize $80 million in federal income tax net operating loss carryforwards to offset tax liabilities related to the prescribed Internal Revenue Service accounting method change that will be filed in connection with this new guidance.


•	In November 2012, the Ameren Companies entered into multiyear credit agreements that cumulatively provide $2.1 billion of credit through November 14, 2017. See Note 4 - 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.

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 3 - 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 risks 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 objective is 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.

Except as discussed below, there have been no material changes to the quantitative and qualitative disclosures about market risk in the Form 10-K. See Item 7A, under Part II, of the Form 10-K for a more detailed discussion of our market risks.

Credit Risk

Credit risk represents the loss that would be recognized if counterparties should fail to perform as contracted. 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 in the event of nonperformance by the counterparties to the transaction. See Note 7 - Derivative Financial Instruments under Part I, Item 1, of this report for information on the potential loss on counterparty exposure as of September 30, 2013.

Our rate-regulated revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables and executory contracts with market risk exposures. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our customer base. At September 30, 2013, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. Additionally, Ameren Illinois has risk associated with the purchase of receivables. The Illinois Public Utilities Act requires Ameren Illinois to establish electric utility consolidated billing and purchase of receivables services. At the option of an alternative retail electric supplier, Ameren Illinois is required to purchase the supplier’s receivables relating to Ameren Illinois’ delivery service customers who elected to receive power supply from the alternative retail electric supplier. When that option is selected, Ameren Illinois produces consolidated bills for the applicable retail customers reflecting charges for electric delivery service and purchased receivables. In June 2012, Ameren Illinois began purchasing trade receivables relating to the power supply of residential customers who use Marketing Company as their alternative retail electric supplier. As of September 30, 2013, Ameren Illinois’ balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $29 million. The risk associated with Ameren Illinois’ electric and natural gas trade receivables is also mitigated by a rate adjustment mechanism that allows Ameren Illinois to recover the difference between its actual net bad debt write-offs under GAAP and the amount of net bad debt write-offs included in its base rates. Ameren Missouri and Ameren Illinois continued to monitor the impact of increasing rates on customer collections. Ameren Missouri and Ameren Illinois make adjustments to their respective allowance for doubtful accounts as deemed necessary to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.

Ameren, Ameren Missouri and Ameren Illinois may have credit exposure associated with off-system or wholesale purchase and sale activity with nonaffiliated companies. At September 30, 2013, Ameren’s, Ameren Missouri’s, and Ameren Illinois’ combined credit exposure to nonaffiliated trading counterparties, excluding coal suppliers, deemed below investment grade either through external or internal credit evaluations, net of collateral, was less than $1 million (2012 - less than $1 million). At September 30, 2013, the combined credit

exposures to coal suppliers deemed below investment grade either through external or internal credit evaluations, net of collateral, was less than $1 million at Ameren and at Ameren Missouri (2012- $2 million).

We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program. Monitoring involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition before we enter into sales, forwards, swaps, futures, or option contracts.

Equity Price Risk

Our costs of providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. To the extent the value of plan assets declines, the effect would be reflected in net income and OCI or regulatory assets, and in the amount of cash required to be contributed to the plans.

Commodity Price Risk

We are exposed to changes in market prices for power, emission allowances, coal, transportation diesel, natural gas and uranium.

Ameren Missouri’s risks of changes in prices for power sales are partially hedged through sales agreements. We also attempt to mitigate financial risks through risk management programs and policies, which include forward-hedging programs, and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). However, a portion of the generation capacity of Ameren Missouri is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.

If power prices were to decrease by 1% on unhedged economic generation for 2013 through 2017, Ameren and Ameren Missouri earnings would decrease by less than $1 million, based on a 36% effective tax rate.

Ameren Missouri has entered into coal contracts with various suppliers to purchase coal to manage its exposure to fuel prices. The coal hedging strategy is intended to secure a reliable coal supply while reducing exposure to commodity price volatility. Additionally, the type of coal burned is part of Ameren Missouri’s environmental compliance strategy. Ameren Missouri has a

multiyear agreement to purchase ultra-low-sulfur coal through 2017 to comply with environmental regulations.

Transportation costs for coal and natural gas can be a significant portion of fuel costs. Ameren Missouri typically hedges coal transportation forward to provide supply certainty and to mitigate transportation price volatility.

In addition, coal and coal transportation costs are sensitive to the price of diesel fuel as a result of rail freight fuel surcharges. We use forward fuel oil contracts (for heating oil, ultra-low sulfur diesel and crude oil) to mitigate this market price risk as changes in these products are highly correlated to changes in diesel markets. If diesel fuel costs were to increase or decrease by $0.25 per gallon, Ameren Missouri’s earnings would increase or decrease by less than $1 million based on a 36% effective tax rate. As of September 30, 2013, Ameren Missouri had a price cap for 100% of expected fuel surcharges in 2013.

With regard to exposure for commodity price risk for nuclear fuel, Ameren Missouri has fixed-priced, base-price-with-escalation, and market-priced agreements. It uses inventories to provide some price hedge to fulfill its Callaway energy center’s needs for uranium, conversion, and enrichment. Ameren Missouri has price hedges for approximately 75% of its 2013 to 2017 nuclear fuel requirements. For the years 2013 through 2017, 2015 is the only year without a fuel reloading or planned maintenance outage.

Ameren Missouri’s electric generating operations are exposed to changes in market prices for natural gas used to run CTs. Its natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas while minimizing costs. We optimize transportation and storage options and price risk by structuring supply agreements to maintain access to multiple gas pools and supply basins.

With regard to Ameren Missouri’s and Ameren Illinois’ electric and natural gas distribution businesses, exposure to changing market prices is largely mitigated by the fact that there are cost recovery mechanisms (e.g. FAC, PGA) in place. These cost recovery mechanisms allow Ameren Missouri and Ameren Illinois to pass on to retail customers prudently incurred costs for fuel, purchased power, and natural gas supply. However, Ameren Missouri’s and Ameren Illinois’ strategy is designed to reduce the effect of market fluctuations for their rate-regulated customers by employing risk management techniques and instruments similar to those outlined above, as well as the management of physical assets.



Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
Material Contracts
10.1	Ameren	*Summary Sheet of Ameren Corporation Non-Management Director Compensation (revised on August 9, 2013 and effective as of August 12, 2013)
10.2	Ameren Companies	*Revised Schedule I to Second Amended and Restated Change of Control Severance Plan, as amended
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 File
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



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



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



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



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



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



ý	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Quarterly Period Ended September 30, 2013



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



Ameren Corporation		Common stock, $0.01 par value per share - 242,634,671
Union Electric Company		Common stock, $5 par value per share, held by Ameren Corporation (parent company of the registrant) - 102,123,834
Ameren Illinois Company		Common stock, no par value, held by Ameren Corporation (parent company of the registrant) - 25,452,373



		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	60
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	85
Item 4.	Controls and Procedures	88

PART II Other Information

Item 1.	Legal Proceedings	89
Item 1A.	Risk Factors	89
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	89
Item 6.	Exhibits	89

Signatures		92


^(a)	Weighted-average number of performance share units that were excluded from the “Assumed settlement of performance share units” provided above because the performance or market conditions related to the awards had not yet been met.



	Performance Share Units
	Share Units		Weighted-average Fair Value Per Unit at Grant Date
Nonvested as of January 1, 2013	1,192,487		$	33.56
Granted^(a)	837,199		31.19
Forfeitures	(7,757	)	32.66
Vested^(b)	(131,960	)	31.30
Nonvested as of September 30, 2013	1,889,969		$	32.67


(a)	Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2013 under the 2006 Plan.


(b)	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.



	Ameren Missouri^(a)		Ameren Illinois^(b)		Other^(c)		Ameren^(a)
Balance at December 31, 2012	$	346	$	3	$	26	$	375
Liabilities incurred	—		—		—		—
Liabilities settled	(d)		(d)		(d)		(d)
Accretion in 2013^(e)	14		(d)		1		15
Change in estimates^(f)	2		(d)		(d)		2
Balance at September 30, 2013	$	362	$	3	$	27	$	392


(a)	The nuclear decommissioning trust fund assets of $459 million and $408 million as of September 30, 2013, and December 31, 2012, respectively, were restricted for decommissioning of the Callaway energy center.


(b)	Balance included in “Other deferred credits and liabilities” on the balance sheet.


(c)	Represents amounts for the Meredosia and Hutsonville energy centers. Pursuant to the transaction agreement to divest New AER to IPH, Ameren will retain the AROs associated with the Meredosia and Hutsonville energy centers. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.


(e)	Accretion was recorded as an increase to regulatory assets at Ameren Missouri and Ameren Illinois.


(f)	Ameren Missouri changed its fair value estimates for asbestos removal and certain CCR storage facilities.


(b)	Represents the noncontrolling interest of EEI’s pension and other postretirement benefit plan activity, net of income taxes of $-, $6, $-, and $6, respectively.


(a)	Includes a noncash pretax impairment charge of $175 million for the nine months ended September 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell.


(b)	Includes a noncash pretax asset impairment charge of $628 million to reduce the carrying value of AERG’s Duck Creek energy center to its estimated fair value under held and used accounting guidance.



	September 30, 2013		December 31, 2012
Assets of discontinued operations
Cash and cash equivalents	$	25	$	25
Accounts receivable and unbilled revenue	102		102
Materials and supplies	121		134
Mark-to-market derivative assets	71		102
Property and plant, net	623		748
Accumulated deferred income taxes, net	357		385
Other assets	96		104
Total assets of discontinued operations	$	1,395	$	1,600
Liabilities of discontinued operations
Accounts payable and other current obligations	$	141	$	133
Mark-to-market derivative liabilities	38		63
Long-term debt, net	824		824
Asset retirement obligations	87		78
Pension and other postretirement benefits	32		40
Other liabilities	19		28
Total liabilities of discontinued operations	$	1,141	$	1,166
Accumulated other comprehensive income^(a)	$	3	$	19
Noncontrolling interest^(b)	$	8	$	8


(a)	Accumulated other comprehensive income related to discontinued operations remains in “Accumulated other comprehensive loss” on Ameren’s September 30, 2013, and December 31, 2012, balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s balance sheet either before or at the closing of the New AER divestiture.


(b)	The 20% ownership interest of EEI not owned by Ameren was included in “Noncontrolling interests” on Ameren’s September 30, 2013, and December 31, 2012, balance sheets. This noncontrolling interest will be removed from Ameren’s balance sheet at the closing of the New AER divestiture.



	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	4.3	$	3,564		≥2.5	111.5	$	2,130
Ameren Illinois	≥2.0	7.4		3,536	^(d)	≥1.5	2.7		203


(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 $485 million and $645 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.


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


(b)	Includes interest income received in 2012 relating to a refund of charges included in an expired power purchase agreement with Entergy.


(c)	Includes Ameren Illinois’ one-time $7.5 million contribution to the Illinois Science and Energy Innovation Trust pursuant to the IEIMA as a result of Ameren Illinois’ 2012 election to participate in the formula ratemaking process.


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