EXHIBIT 99.4

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Ameren Corporation

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income (loss), comprehensive income (loss), stockholders’ equity and cash flows present fairly, in all material respects, the financial position of Ameren Corporation and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules included in Exhibits 99.5 and 99.6 of this Current Report on Form 8-K present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting(not presented herein)appearing under Item 9Aof the Company’s 2012 Annual Report on Form 10-K.Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 1, 2013, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of discontinued operations discussed in Note 16, as to which the date is October 17, 2013

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AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME (LOSS) (In millions, except per share amounts)
	Year Ended December 31,
	2012			2011		2010
Operating Revenues:
Electric	$	4,857		$	5,226	$	5,153
Gas	924			1,001		1,116
Total operating revenues	5,781			6,227		6,269
Operating Expenses:
Fuel	714			911		673
Purchased power	780			952		1,122
Gas purchased for resale	472			570		668
Other operations and maintenance	1,514			1,580		1,566
Impairment and other charges	—			123		64
Depreciation and amortization	667			646		627
Taxes other than income taxes	443			434		424
Total operating expenses	4,590			5,216		5,144
Operating Income	1,191			1,011		1,125
Other Income and Expenses:
Miscellaneous income	70			68		88
Miscellaneous expense	37			23		32
Total other income	33			45		56
Interest Charges	391			387		415
Income Before Income Taxes	833			669		766
Income Taxes	309			245		274
Income from Continuing Operations	524			424		492
Income (Loss) from Discontinued Operations, Net of Taxes (Note 16)	(1,498		)	102		(341		)
Net Income (Loss)	(974		)	526		151
Less: Net Income (Loss) Attributable to Noncontrolling Interests:
Continuing Operations	6			6		9
Discontinued Operations	(6		)	1		3
Net Income (Loss) Attributable to Ameren Corporation:
Continuing Operations	518			418		483
Discontinued Operations	(1,492		)	101		(344		)
Net Income (Loss) Attributable to Ameren Corporation	$	(974	)	$	519	$	139
Earnings (Loss) per Common Share – Basic and Diluted:
Continuing Operations	$	2.13		$	1.73	$	2.02
Discontinued Operations	(6.14		)	0.42		(1.44		)
Earnings (Loss) per Common Share – Basic and Diluted	$	(4.01	)	$	2.15	$	0.58
Dividends per Common Share	$	1.600		$	1.555	$	1.540
Average Common Shares Outstanding	242.6			241.5		238.8

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

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AMEREN CORPORATION CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) (In millions)
	Year Ended December 31,
	2012			2011			2010
Income from Continuing Operations	$	524		$	424		$	492
Other Comprehensive Income (Loss), Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes(benefit) of $(6), $(14), and $7, respectively	(8		)	(19		)	10
Comprehensive Income from Continuing Operations	516			405			502
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests	6			6			9
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation	510			399			493
Income (Loss) from Discontinued Operations, Net of Income Taxes	(1,498		)	102			(341		)
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Income Taxes	58			(20		)	(16		)
Comprehensive Income (Loss) from Discontinued Operations	(1,440		)	82			(357		)
Less: Comprehensive Income (Loss) from Discontinuing Operations Attributable to Noncontrolling Interest	2			(5		)	1
Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Corporation	(1,442		)	87			(358		)
Comprehensive Income (Loss) Attributable to Ameren Corporation	$	(932	)	$	486		$	135

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

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AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (In millions, except per share amounts)
	December 31,
	2012			2011
ASSETS
Current Assets:
Cash and cash equivalents	$	184		$	248
Accounts receivable – trade (less allowance for doubtful accounts of $17 and $20, respectively)	354			424
Unbilled revenue	291			285
Miscellaneous accounts and notes receivable	71			48
Materials and supplies	570			550
Current regulatory assets	247			215
Current accumulated deferred income taxes, net	170			98
Other current assets	98			151
Assets of discontinued operations (Note 16)	1,600			3,718
Total current assets	3,585			5,737
Property and Plant, Net	15,348			14,848
Investments and Other Assets:
Nuclear decommissioning trust fund	408			357
Goodwill	411			411
Intangible assets	14			7
Regulatory assets	1,786			1,603
Other assets	667			760
Total investments and other assets	3,286			3,138
TOTAL ASSETS	$	22,219		$	23,723
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	355		$	179
Short-term debt	—			148
Accounts and wages payable	533			592
Taxes accrued	50			53
Interest accrued	89			91
Customer deposits	107			98
Mark-to-market derivative liabilities	92			122
Current regulatory liabilities	100			133
Other current liabilities	168			195
Liabilities of discontinued operations (Note 16)	1,166			1,762
Total current liabilities	2,660			3,373
Long-term Debt, Net	5,802			5,853
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	3,176			2,810
Accumulated deferred investment tax credits	70			76
Regulatory liabilities	1,589			1,502
Asset retirement obligations	375			364
Pension and other postretirement benefits	1,138			1,253
Other deferred credits and liabilities	642			424
Total deferred credits and other liabilities	6,990			6,429
Commitments and Contingencies (Notes 2, 10, 14, 15 and 16)
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	5,616			5,598
Retained earnings	1,006			2,369
Accumulated other comprehensive loss	(8		)	(50		)
Total Ameren Corporation stockholders’ equity	6,616			7,919
Noncontrolling Interests	151			149
Total equity	6,767			8,068
TOTAL LIABILITIES AND EQUITY	$	22,219		$	23,723

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

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AMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (In millions)
	Year Ended December 31,
	2012			2011			2010
Cash Flows From Operating Activities:
Net income (loss)	$	(974	)	$	526		$	151
(Income) loss from discontinued operations, net of taxes	1,498			(102		)	341
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairment and other charges	—			123			64
Net gain on sales of properties	—			(3		)	(5		)
Depreciation and amortization	627			606			590
Amortization of nuclear fuel	83			61			54
Amortization of debt issuance costs and premium/discounts	20			16			16
Deferred income taxes and investment tax credits, net	260			253			384
Allowance for equity funds used during construction	(36		)	(34		)	(52		)
Stock-based compensation costs	29			17			15
Other	(8		)	(14		)	1
Changes in assets and liabilities:
Receivables	30			200			(232		)
Materials and supplies	(25		)	(27		)	19
Accounts and wages payable	(34		)	(31		)	23
Taxes accrued	(3		)	(5		)	18
Assets, other	(6		)	59			(47		)
Liabilities, other	58			(68		)	88
Pension and other postretirement benefits	(23		)	(100		)	(9		)
Counterparty collateral, net	41			36			(70		)
Premiums paid on long-term debt repurchases	(138		)	—			—
Taum Sauk insurance recoveries, net of costs	—			(1		)	54
Net cash provided by operating activities - continuing operations	1,399			1,512			1,403
Net cash provided by operating activities - discontinued operations	291			366			420
Net cash provided by operating activities	1,690			1,878			1,823
Cash Flows From Investing Activities:
Capital expenditures	(1,063		)	(881		)	(941		)
Nuclear fuel expenditures	(91		)	(62		)	(68		)
Purchases of securities – nuclear decommissioning trust fund	(403		)	(220		)	(271		)
Sales and maturities of securities – nuclear decommissioning trust fund	384			199			256
Proceeds from sales of properties	—			3			7
Tax grants received related to renewable energy properties	18			—			—
Other	2			12			2
Net cash used in investing activities - continuing operations	(1,153		)	(949		)	(1,015		)
Net cash used in investing activities - discontinued operations	(157		)	(99		)	(81		)
Net cash used in investing activities	(1,310		)	(1,048		)	(1,096		)
Cash Flows From Financing Activities:
Dividends on common stock	(382		)	(375		)	(368		)
Dividends paid to noncontrolling interest holders	(6		)	(6		)	(8		)
Short-term debt and credit facility repayments, net	(148		)	(481		)	(221		)
Redemptions, repurchases, and maturities:
Long-term debt	(760		)	(155		)	(110		)
Preferred stock	—			—			(52		)
Issuances:
Long-term debt	882			—			—
Common stock	—			65			80
Capital issuance costs	(16		)	—			(9		)
Advances received for construction	4			5			29
Repayments of advances received for construction	—			(73		)	(39		)
Net cash used in financing activities - continuing operations	(426		)	(1,020		)	(698		)
Net cash used in financing activities - discontinued operations	—			(100		)	(106		)
Net cash used in financing activities	(426		)	(1,120		)	(804		)
Net change in cash and cash equivalents	(46		)	(290		)	(77		)
Cash and cash equivalents at beginning of year	255			545			622
Cash and cash equivalents at end of year	$	209		$	255		$	545
Less cash and cash equivalents of discontinued operations at end of year	25			7			7
Cash and cash equivalents of continuing operations at end of year	$	184		$	248		$	538
Noncash financing activity – dividends on common stock	$	(7	)	$	—		$	—
Cash Paid (Refunded) During the Year:
Interest (net of $30, $30, and $34 capitalized, respectively)	$	433		$	453		$	494
Income taxes, net	1			(61		)	(92		)

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

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AMEREN CORPORATION CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (In millions)
	December 31,
	2012			2011			2010
Common Stock:
Beginning of year	$	2		$	2		$	2
Shares issued	—			—			—
Common stock, end of year	2			2			2
Other Paid-in Capital:
Beginning of year	5,598			5,520			5,412
Shares issued	—			65			80
Stock-based compensation activity	18			13			14
Regulatory recovery of prior-period common stock issuance costs	—			—			14
Other paid-in capital, end of year	5,616			5,598			5,520
Retained Earnings:
Beginning of year	2,369			2,225			2,455
Net income (loss) attributable to Ameren Corporation	(974		)	519			139
Dividends	(389		)	(375		)	(368		)
Other	—			—			(1		)
Retained earnings, end of year	1,006			2,369			2,225
Accumulated Other Comprehensive Loss:
Derivative financial instruments, beginning of year	7			—			10
Change in derivative financial instruments	18			7			(10		)
Derivative financial instruments, end of year	25			7			—
Deferred retirement benefit costs, beginning of year	(57		)	(17		)	(23		)
Change in deferred retirement benefit costs	24			(40		)	6
Deferred retirement benefit costs, end of year	(33		)	(57		)	(17		)
Total accumulated other comprehensive loss, end of year	(8		)	(50		)	(17		)
Total Ameren Corporation Stockholders’ Equity	$	6,616		$	7,919		$	7,730
Noncontrolling Interests:
Beginning of year	149			154			204
Net income attributable to noncontrolling interest holders	—			7			12
Dividends paid to noncontrolling interest holders	(6		)	(6		)	(8		)
Redemptions of preferred stock	—			—			(52		)
Other	8			(6		)	(2		)
Noncontrolling interests, end of year	151			149			154
Total Equity	$	6,767		$	8,068		$	7,884
Common stock shares at beginning of year	242.6			240.4			237.4
Shares issued	—			2.2			3.0
Common stock shares at end of year	242.6			242.6			240.4

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

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NOTES TO FINANCIAL STATEMENTS

December 31, 2012

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 other expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.

• Union Electric Company, or 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 Missouri was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the state of Missouri. It supplies electric and natural gas service to a 24,000-square-mile area in central and eastern Missouri. This area has an estimated population of 2.8 million and includes the Greater St. Louis area. Ameren Missouri supplies electric service to 1.2 million customers and natural gas service to 127,000 customers.

• Ameren Illinois Company, or Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. Ameren Illinois was created by the merger of CILCO and IP with and into CIPS. CIPS was incorporated in Illinois in 1923 and is successor to a number of companies, the oldest of which was organized in 1902. Ameren Illinois supplies electric and natural gas utility service to portions of central and southern Illinois having an estimated population of 3.1 million in an area of 40,000 square miles. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 806,000 customers.

• AER consists of non-rate-regulated operations, including Genco, AERG, Marketing Company, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes. On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding the divestiture.

Ameren has various other subsidiaries responsible for activities such as the provision of shared services.

In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation

business before the end of the previously estimated useful lives of that business's long-lived assets. This determination resulted from Ameren’s analysis of the current and projected future financial condition of its Merchant Generation business segment, including the need to fund Genco debt maturities beginning in 2018, and its conclusion that this business segment is no longer a core component of its future business strategy. In consideration of this determination, Ameren has begun planning to reduce, and ultimately eliminate, the Merchant Generation business segment’s, including Genco's, reliance on Ameren’s financial support and shared services support. Furthermore, Ameren recorded a noncash long-lived asset impairment charge to reduce the carrying values of the Merchant Generation energy centers, except for the Joppa coal-fired energy center, to their estimated fair values. See Note 16 - Divestiture Transactions and Discontinued Operations.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH, which Ameren expects will occur in 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 for the pending 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. Ameren expects a third-party sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers will be completed by the end of 2013. See Note 16 - 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 on 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 noted, these notes to the financial statements have been revised to exclude discontinued operations for all periods presented. All other information herein remains unchanged. The information contained herein does not modify or update the disclosures contained in Ameren's Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on March 1, 2013, in any way, nor does it reflect any subsequent information or events, other than as required to reflect the results of the discontinued operations presentation described above. Information presented for the Ameren Missouri and Ameren Illinois registrants also remains unchanged. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding that presentation.

The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All significant intercompany

7

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.

Regulation

Certain Ameren subsidiaries are regulated by the MoPSC, the ICC, and FERC. In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, Ameren Missouri and Ameren Illinois defer certain costs as assets pursuant to actions of rate regulators or because of expectations that the companies will be able to recover such costs in rates charged to customers. Ameren Missouri and Ameren Illinois also defer certain amounts as liabilities pursuant to actions of rate regulators or based on the expectation that such amounts will be returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. In addition to the cost recovery mechanisms discussed in the Purchased Gas, Power and Fuel Rate-adjustment Mechanisms section below, Ameren Missouri and Ameren Illinois have approvals from regulators to use other cost recovery mechanisms. Ameren Missouri has a vegetation management and infrastructure inspection cost tracker, pension and postretirement benefit cost tracker, uncertain tax positions tracker, renewable energy standards cost tracker, and, starting in 2013, a storm restoration cost tracker and the MEEIA energy efficiency cost recovery mechanisms. Ameren Illinois has an environmental cost rider, asbestos-related litigation rider, energy efficiency rider, and a bad debt rider. See Note 2 - Rate and Regulatory Matters for additional information on regulatory assets and liabilities. In addition, other costs that Ameren Missouri and Ameren Illinois expect to recover from customers are recorded as construction work in progress and property and plant, net. See Note 3 - Property and Plant, Net.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.

Allowance for Doubtful Accounts Receivable

The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated loss factors to various classes of outstanding receivables, including unbilled revenue. The loss factors used to estimate uncollectible accounts are based upon both historical collections

experience and management’s best estimate of future collections success given the existing and anticipated future collections environment. Ameren Illinois has a rate mechanism that adjusts rates for bad debt expense above or below those being collected in rates.

Materials and Supplies

Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when installed, as appropriate. The following table presents a breakdown of materials and supplies at December 31, 2012, and 2011:

2012
Fuel(a)	$	198
Gas stored underground	131
Other materials and supplies	241
	$	570
2011
Fuel(a)	$	150
Gas stored underground	171
Other materials and supplies	229
	$	550

(a) Consists of coal, oil, paint, propane, and tire chips.

Property and Plant

We capitalize the cost of additions to and betterments of units of property and plant. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, as discussed specifically below, is also capitalized as a cost of our rate-regulated assets. Maintenance expenditures, including nuclear refueling and maintenance outages, are expensed as incurred. When units of depreciable property are retired, the original costs, less salvage values, are charged to accumulated depreciation. Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Asset Retirement Obligations below and Note 3 - Property and Plant, Net, for additional information.

Depreciation

Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property. The provision for depreciation for the Ameren Companies in 2012, 2011 and 2010 ranged from 3% to 4% of the average depreciable cost.

Allowance for Funds Used During Construction

In our rate-regulated operations, we capitalize the allowance for funds used during construction, or the cost of borrowed funds and the cost of equity funds (preferred and common stockholders’ equity) applicable to rate-regulated construction

8

expenditures, as is the utility industry's accounting practice. Allowance for funds used during construction does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing during construction, and it treats such financing costs in the same manner as construction charges for labor and materials.

Under accepted ratemaking practice, cash recovery of allowance for funds used during construction and other construction costs occurs when completed projects are placed in service and reflected in customer rates. The annual allowance for funds used during construction rates that were utilized during 2012, 2011 and 2010 were 8% to 9% for all years.

Goodwill and Intangible Assets

Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. As of December 31, 2012, Ameren’s goodwill related to the acquisitions of IP in 2004 and of CILCORP in 2003.

Ameren has three reporting units, which also represent Ameren’s reportable segments. Ameren's reporting units are Ameren Missouri, Ameren Illinois, and Merchant Generation. Ameren’s reporting units have been defined and goodwill has been evaluated at the operating segment level in accordance with authoritative accounting guidance. Our reporting units represent businesses for which discrete financial information is available and reviewed regularly by management. All of Ameren's goodwill at December 31, 2012, and 2011 has been assigned to the Ameren Illinois reporting unit.

We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Ameren applied a qualitative goodwill evaluation model for its annual goodwill impairment test conducted as of October 31, 2012. Based on the results of Ameren’s qualitative assessment, Ameren believes it was more likely than not that the fair value of the Ameren Illinois reporting unit exceeded its carrying value as of October 31, 2012, indicating no impairment of Ameren’s goodwill. The following factors, not meant to be all-inclusive, were considered by Ameren when assessing whether it was more likely than not that the fair value of the Ameren Illinois reporting unit exceeded its carrying value for the October 31, 2012, test:

• Macroeconomic conditions, including those conditions within Ameren Illinois’ service territory;

• Pending rate case outcomes and future rate case outcomes;

• Changes in laws and potential law changes;

• Observable industry market multiples;

• Achievement of IEIMA performance metrics and the yield of the 30-year United States treasury bonds; and

• Actual and forecasted financial performance.

The goodwill assigned to the Ameren Illinois reporting unit on Ameren's December 31, 2012 consolidated balance sheet had no accumulated goodwill impairment losses. Ameren will continue to monitor the actual and forecasted operating results, cash flows, market capitalization, and observable industry market

multiples of the Ameren Illinois reporting unit for signs of possible declines in estimated fair value and potential goodwill impairment.

Intangible Assets. Ameren classifies emission allowances and renewable energy credits as intangible assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

At December 31, 2012, Ameren’s intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of Ameren’s renewable energy credits was $14 million and $7 million at December 31, 2012, and 2011, respectively.

Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. Ameren recorded amortization expense based on usage of renewable energy credits and emission allowances, net of gains from sales, of $4 million, $3 million, and $13 million during the years ended December 31, 2012, 2011, and 2010, respectively.

During 2011, Ameren recorded a $1 million impairment of its SO₂ emission allowances by reducing a previously established regulatory liability relating to the SO₂ emission allowances, which had no impact on earnings. The impairment was triggered by a significant observable decline in the market price of SO₂ and NO_X allowances used for CAIR compliance.

Impairment of Long-lived Assets

We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which we determine an asset meets held for sale criteria, we record an impairment charge to the extent the book value exceeds its fair value less cost to sell. See Note 16 - Divestiture Transactions and Discontinued Operations and Note 17 - Impairment and Other Changes for additional information about Ameren’s long-lived asset impairments.

Investments

Ameren evaluates for impairment the investments held in Ameren Missouri's nuclear decommissioning trust fund. Losses on assets in the trust fund could result in higher funding requirements for decommissioning costs, which Ameren believes would be recovered in electric rates paid by its customers. Accordingly, Ameren recognizes a regulatory asset on its consolidated balance sheet for losses on investments held in the nuclear decommissioning trust fund. See Note 9 - Nuclear

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Decommissioning Trust Fund Investments for additional information.

Environmental Costs

Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are expensed or deferred as a regulatory asset when it is expected that the costs will be recovered from customers in future rates. If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.

Unamortized Debt Discount, Premium, and Expense

Discount, premium, and expense associated with long-term debt are amortized over the lives of the related issues.

Revenue

The Ameren Companies record operating revenue for electric or natural gas service when it is delivered to customers. We accrue an estimate of electric and natural gas revenues for service rendered but unbilled at the end of each accounting period.

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 best estimate of the electric distribution revenue impact resulting from the reconciliation of the revenue requirement necessary to reflect the actual costs incurred for that year with the revenue requirement that was in effect for that year. 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 2 - Rate and Regulatory Matters for information regarding Ameren Illinois' revenue requirement reconciliation pursuant to the IEIMA.

Beginning in 2013, Ameren Illinois will record the impact of a revenue requirement reconciliation for its electric transmission jurisdiction, pursuant to FERC-approved rate treatment.

Nuclear Fuel

Ameren Missouri’s cost of nuclear fuel is capitalized and then amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost is based on net kilowatthours generated

and sold, and that cost is charged to "Operating Expenses - Fuel" in the consolidated statement of income (loss).

Purchased Gas, Power and Fuel Rate-adjustment Mechanisms

Ameren Missouri and Ameren Illinois have various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas and electric fuel and purchased power costs. See Note 2 - Rate and Regulatory Matters for the regulatory assets and liabilities recorded at December 31, 2012, and 2011, related to the rate-adjustment mechanisms discussed below.

In Ameren Missouri’s and Ameren Illinois’ retail natural gas utility jurisdictions, changes in natural gas costs are reflected in billings to their natural gas utility customers through PGA clauses. The differences between actual natural gas costs and costs billed to customers in a given period are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to natural gas utility customers in a subsequent period.

In Ameren Illinois’ retail electric utility jurisdictions, changes in purchased power costs and transmission service cost are reflected in billings to their electric utility customers through pass-through rate-adjustment clauses. The differences between actual purchased power and transmission service costs and costs billed to customers in a given period are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to electric utility customers in a subsequent period.

Ameren Missouri has a FAC that allows an adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel, certain fuel additives, emission allowances, purchased power costs, transmission costs, and MISO costs and revenues, net of off-system revenues, greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudency review. The differences between the cost of fuel incurred and the cost of fuel recovered from Ameren Missouri customers' base rates are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to Ameren Missouri’s electric utility customers in a subsequent period. The MoPSC's December 2012 electric rate order changed the FAC to include activated carbon, limestone and urea costs, along with transmission revenues starting in 2013.

Accounting for MISO Transactions

MISO-related purchase and sale transactions are recorded by Ameren using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. We record net purchases in a single hour in “Operating Expenses - Purchased power” and net sales in a single hour in “Operating Revenues - Electric” in our statements of income (loss). On occasion, prior-period transactions will be resettled outside the routine settlement process because of a change in MISO’s tariff or a material interpretation thereof. In these cases, the Ameren Companies recognize expenses associated with resettlements once the resettlement is probable

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and the resettlement amount can be estimated, and the Ameren Companies recognize revenues once the resettlement amount is received.

Stock-based Compensation

Stock-based compensation cost is measured at the grant date based on the fair value of the award. Ameren recognizes as compensation expense the estimated fair value of stock-based compensation on a straight-line basis over the requisite service period. See Note 12 - Stock-based Compensation for additional information.

Excise Taxes

Excise taxes levied on us are reflected on Ameren Missouri customer electric bills and on Ameren Missouri and Ameren Illinois customer natural gas bills. They are recorded gross in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” on the consolidated statement of income (loss). Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the customer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in “Taxes accrued” on the consolidated balance sheet. Ameren recorded excise taxes in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” of $193 million, $194 million, and $189 million for the years ended December 31, 2012, 2011, and 2010, respectively.

Income Taxes

Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.

We recognize that regulators will probably reduce future revenues for deferred tax liabilities that were initially recorded at rates in excess of the current statutory rate. Therefore, reductions in the deferred tax liability, which were recorded because of decreases in the statutory rate, have been credited to a regulatory liability. A regulatory asset has been established to recognize the probable recovery in rates of future income taxes, resulting principally from the reversal of allowance for funds used during construction. This refers to equity and temporary differences related to property and plant acquired before 1976 that were unrecognized temporary differences prior to the adoption of the authoritative accounting guidance for income taxes.

Investment tax credits used on tax returns for prior years have been deferred for book purposes; the credits are being amortized over the useful lives of the related investment. Deferred income taxes were recorded on the temporary difference represented by the deferred investment tax credits and

a corresponding regulatory liability. This recognizes the expected reduction in rate revenue for future lower income taxes associated with the amortization of the investment tax credits. See Note 13 - Income Taxes.

For certain renewable energy construction projects placed in service in 2010 and 2012, Ameren Missouri elected to seek federal cash tax grants in lieu of investment tax credits for which the projects also qualified.  These grants were accounted for using a grant recognition accounting model.  Ameren Missouri elected to reduce the basis of property as cash grants are received, which will reduce the amount of depreciation expense recognized in future periods.  In 2012, Ameren Missouri received $18 million in federal cash tax grants.

Ameren Missouri, Ameren Illinois, and all the other Ameren subsidiary companies are parties to a tax allocation agreement with Ameren that provides for the allocation of consolidated tax liabilities. The tax allocation agreement specifies that each party be allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution of capital to the party receiving the benefit.

Noncontrolling Interests

Ameren’s noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren’s subsidiaries. These noncontrolling interests are classified as a component of equity separate from Ameren’s equity in its consolidated balance sheet. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information.

Earnings per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts in 2012, 2011, and 2010. The number of dilutive stock options, restricted stock shares, and performance share units had an immaterial impact on earnings per share. There were no assumed stock option conversions in 2010, as the remaining stock options were not dilutive. All of Ameren’s stock options expired in February 2010.

Accounting Changes and Other Matters

The following is a summary of recently adopted authoritative accounting guidance as well as guidance issued but not yet adopted that could impact the Ameren Companies.

Disclosures about Fair Value Measurements

In May 2011, FASB issued additional authoritative guidance regarding fair value measurements. The guidance amended the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments did not affect Ameren's results of operations, financial position, or liquidity, as this

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guidance only requires additional disclosures. The Ameren Companies adopted this guidance for the first quarter of 2012. See Note 8 - Fair Value Measurements for the required additional disclosures.

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of 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 Ameren's results of operations, financial position, or liquidity.

In February 2013, the 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. The amendments will not affect Ameren's results of operations, financial position, or liquidity, as this guidance only requires additional disclosures and substantially all the information that this amended guidance requires is already disclosed elsewhere in the financial statements. This guidance will be effective for the Ameren Companies beginning in the first quarter of 2013 on a prospective basis.

Disclosures about Offsetting Assets and Liabilities

In December 2011, FASB issued additional authoritative 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 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 amendments will not affect Ameren's results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. This guidance will be effective for the Ameren Companies beginning in the first quarter of 2013 with retrospective application required.

Asset Retirement Obligations

Authoritative accounting guidance requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments to AROs based on changes in the estimated fair values of the

obligations. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing, or amount of cash flows associated with AROs affect our estimates of fair value. Ameren has recorded AROs for retirement costs associated with Ameren Missouri for the Callaway energy center decommissioning costs, CCR storage facilities, and river structures. Also, Ameren has recorded AROs for retirement costs associated with Ameren Missouri and Ameren Illinois for asbestos removal and the disposal of certain transformers. After the New AER divestiture is complete, Ameren will retain the AROs associated with the Meredosia and Hutsonville energy centers.

Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Note 2 - Rate and Regulatory Matters.

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2012 and 2011:

	Ameren(a)
Balance at December 31, 2010	$	403
Liabilities incurred	—
Liabilities settled	(2		)
Accretion in 2011(b)	22
Change in estimates(c)	(54		)
Balance at December 31, 2011	$	369		(d)
Liabilities incurred	—
Liabilities settled	(6		)
Accretion in 2012(b)	20
Change in estimates(e)	(8		)
Balance at December 31, 2012	$	375

(a) The nuclear decommissioning trust fund assets of 408 million and 357 million as of December 31, 2012, and 2011, respectively, were restricted for decommissioning of the Callaway energy center.

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

(c) Ameren changed its fair value estimate related to its Callaway energy center decommissioning costs because of a cost study performed in 2011 and a decline in the cost escalation factor assumptions. Additionally, Ameren changed the fair value estimates related to retirement costs for asbestos removal, river structures and CCR storage facilities.

(d) Balance included $5 million in "Other current liabilities" on the consolidated balance sheet as of December 31, 2011.

(e) Ameren changed the fair value estimates for asbestos removal. The estimates for asbestos removal costs at Hutsonville and Meredosia energy centers decreased because less asbestos than anticipated was found in the energy centers' structures during reviews made after the closure of these energy centers, and because removal was more cost efficient than anticipated due to the closure.

Employee Separation Charges

During the fourth quarter of 2011, as part of efforts to reduce operations and maintenance expenses, Ameren Missouri and Ameren Services extended voluntary separation offers consistent with Ameren's standard management separation program to eligible management and labor union-represented employees. Approximately 340 employees of Ameren Missouri and Ameren Services accepted the offers and left their employment by December 31, 2011. Ameren recorded a pretax

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charge to earnings of $28 million for the severance costs related to these offers. These charges were recorded in “Other operations and maintenance" expense in the consolidated statement of income (loss) for the year ended December 31, 2011. Substantially all of the severance costs were paid in the first quarter of 2012 and were recorded in “Accounts and wages payable” on the consolidated balance sheet at December 31, 2011.

In 2011, the Meredosia and Hutsonville energy centers initiated separation programs to reduce positions under the terms and benefits consistent with Ameren's standard management separation program. Ameren recorded pretax charges related to these programs of $4 million in 2011. The charge was recorded in "Impairment and other charges" on the consolidated statement of income (loss). See Note 17 - Impairment and Other Charges for additional information.

NOTE 2 - RATE AND REGULATORY MATTERS

Below is a summary of significant regulatory proceedings and related lawsuits. 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

2009, 2010, and 2011 Electric Rate Orders

Noranda, Ameren Missouri's largest electric customer, and the MoOPC appealed certain aspects of the MoPSC's January 2009 electric rate order to the Stoddard County Circuit Court. In September 2009, the Stoddard County Circuit Court issued a stay of the electric order as it applied specifically to Noranda's electric service account, which allowed Noranda to pay a portion of its monthly billings into the Stoddard County Circuit Court's registry until the court ultimately rendered a decision on the appeal. In August 2010, the Stoddard County Circuit Court issued a judgment that reversed part of the MoPSC's January 2009 electric rate order. However, upon issuance, the Stoddard County Circuit Court suspended its own judgment. Ameren Missouri appealed the Stoddard County Circuit Court's judgment and, in November 2011, the Missouri Court of Appeals issued a ruling that upheld the MoPSC's January 2009 electric rate order. In March 2012, the Stoddard County Circuit Court released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $21 million, reducing the previously recorded trade accounts receivable.

In May 2010, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $230 million. The MIEC, MoOPC, and four industrial customers appealed certain aspects of the MoPSC's May 2010 electric rate order to the Cole County Circuit Court. In December 2010, the Cole County Circuit Court issued a stay of the electric order as it applied specifically to four industrialcustomers' electric service accounts, which allowed them to pay a portion of their monthly billings into the Cole County Circuit Court's registry until thecourt ultimately rendered a decision on the appeal. In May

2012, the Cole County Circuit Court issued a ruling that upheld the MoPSC's May 2010 electric rate order and released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $16 million, reducing the previously recorded trade accounts receivable.

In July 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $173 million, including $52 million related to an increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its May 2010 electric rate order. The MoPSC's July 2011 electric rate order disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance. As a result, Ameren recorded in 2011 a pretax charge to earnings of $89 million. Ameren recorded the charge to “Impairment and other charges.” See Note 17 - Impairment and Other Charges for additional information. In July 2012, the Missouri Court of Appeals upheld the MoPSC's July 2011 electric rate order. Ameren Missouri did not seek further appeal of the MoPSC order.

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, including $84 million related to an anticipated increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its July 2011 electric rate order. The annual increase request also includes $80 million for recovery of the costs associated with energy efficiency programs under the MEEIA, which are discussed below. The remaining annual increase of $96 million approved by the MoPSC was for energy infrastructure investments and other nonfuel costs, including $10 million for increased pension and other post-employment benefit costs and $6 million for increased amortization of regulatory assets. The revenue increase was based on a 9.8% return on equity, a capital structure composed of 52.3% common equity, and a rate base of $6.8 billion.

The MoPSC approved Ameren Missouri's continued use of its FAC, with no change to its 95% sharing percentage, but with a modification relating to transmission revenues. Transmission revenues previously included in base rates will be included in the FAC prospectively. This change resulted in the portion of the rate increase attributed to net fuel costs being reduced, and the portion attributed to other nonfuel costs being increased, by $33 million as compared to base rates authorized in the MoPSC's July 2011 electric rate order. This change in regulatory treatment will have no immediate impact on earnings. Transmission charges that had previously been included in the FAC remain in the FAC. Further, the order clarified that changes in costs for activated carbon, limestone and urea are included in the FAC. The MoPSC order approved the continued use of Ameren Missouri's vegetation management and infrastructure inspection cost tracker, pension and postretirement benefit cost tracker,

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renewable energy standards cost tracker, and the uncertain tax positions tracker.

The order also established a storm restoration cost tracking mechanism to facilitate the recovery in future rate cases of storm costs that vary from those included in rates and allowed retention of the refund received in June 2012 from Entergy related to a power purchase agreement that existed prior to the implementation of the FAC. See below under Federal for additional information about this refund, which remains subject to appeal, and Ameren Missouri's power purchase agreement with Entergy. However, the MoPSC did not approve Ameren Missouri's request for plant-in-service accounting treatment for assets placed in service between rate cases or recovery of its 2011 severance costs.

Rate changes consistent with the order became effective on January 2, 2013. In January 2013, Ameren Missouri appealed the amount of property taxes included in the 2012 electric rate order to the Missouri Court of Appeals, Western District. In February 2013, the MoOPC, the MIEC and others 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 and other items. A decision is expected by the Missouri Court of Appeals, Western District, in 2013. Ameren Missouri cannot predict the ultimate outcome of its appeal.

MEEIA Order

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

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 approximately $147 million over the next three years for energy efficiency programs. The order allows for Ameren Missouri to collect its program costs and 90% of its projected lost revenue from customers over the same three years starting on January 2, 2013. The remaining 10% of projected lost revenue is expected to be recovered as part of future rate proceedings.

Additionally, the order provides for an incentive award that would allow Ameren Missouri to earn additional revenues based on achievement of certain energy efficiency goals, including approximately $19 million if 100% of its energy efficiency goals are achieved during the three-year period, with the potential to earn more if Ameren Missouri's energy savings exceed those goals. Ameren Missouri must achieve at least 70% of its energy efficiency goals before it earns any incentive award. The recovery

of the incentive award from customers, if the energy efficiency goals are achieved, would begin after the three-year energy efficiency plan is complete and upon the effective date of an electric service rate order or potentially with the future adoption of a rider mechanism.

FAC Prudence Review

Missouri law requires the MoPSC to perform prudence reviews of Ameren Missouri's FAC at least every 18 months. 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. As a result of the order, Ameren recorded a pretax charge to earnings of $18 million, including $1 million for interest, in 2011 for its obligation to refund to Ameren Missouri's electric customers the earnings associated with these sales previously recognized by Ameren during the period from March 1, 2009, to September 30, 2009.

Ameren Missouri disagrees with the MoPSC order's classification of these sales and believes that the terms of its FAC tariff did not provide for the inclusion of these sales in the FAC calculation. 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 filed an appeal of the Cole County Circuit Court's ruling to the Missouri Court of Appeals, Western District. Ameren Missouri has not recorded additional revenues as a result of the Cole County Circuit Court's May 2012 ruling, as the MoPSC's appeal to the Missouri Court of Appeals is ongoing. A decision is expected to be issued in 2013.

In February 2012, the MoPSC staff issued its FAC review report for the period from October 1, 2009, to May 31, 2011. In its report, the MoPSC staff asked the MoPSC to direct Ameren Missouri to refund to customers the pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC staff calculated these pretax earnings to be $26 million. Missouri law does not impose a specific deadline by which the MoPSC must complete its prudence reviews. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri's electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made. Ameren Missouri does not currently believe these amounts are probable of refund to customers.

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. We cannot predict the ultimate outcome of these regulatory or judicial proceedings. If the courts ultimately rule in favor of Ameren Missouri's position

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regarding the classification of the long-term partial requirements sales, Ameren Missouri would not seek to recover from customers the sum that would be covered by the accounting authority order, if it is granted.

Regional Transmission Organization

Ameren Missouri is a transmission-owning member of MISO. In April 2012, the MoPSC authorized Ameren Missouri's continued conditional MISO participation through May 2016, including the condition that Ameren Missouri later file a further study with the MoPSC that evaluates the costs and benefits of Ameren Missouri's continued participation in MISO, as it has periodically done since its MISO participation began in 2003. The next cost benefit study is required to be filed with the MoPSC in November 2015.

Illinois

IEIMA

Ameren Illinois' initial filing to participate in the performance based formula ratemaking process under the IEIMA was based on 2010 recoverable costs and expected net plant additions for 2011 and 2012. In September 2012, the ICC issued an order approving an Ameren Illinois electric delivery service revenue requirement of $779 million, which was a $55 million decrease from the electric delivery service revenue requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The rates became effective on October 19, 2012, and were effective through the end of 2012. In October 2012, Ameren Illinois filed an appeal of the ICC's initial filing order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013. Ameren Illinois believes that the ICC has incorrectly implemented the IEIMA by using an average rate base as opposed to a year-end rate base in setting rates, through its treatment of accumulated deferred income taxes, and through the method it used for calculating the equity portion of Ameren Illinois' capital structure and the method for calculating interest on the revenue requirement reconciliation and return on equity collar. The ICC's September 2012 order jeopardizes Ameren Illinois' ongoing ability to implement infrastructure improvements to the extent and on the timetable envisioned in the IEIMA. Until the uncertainty surrounding how the Illinois law will ultimately be implemented is removed, Ameren Illinois is slowing IEIMA capital spending with a corresponding negative effect on the job creation that the legislature sought to effectuate with the law. Although Ameren Illinois intends to meet its IEIMA capital spending requirements, it is proceeding on a slower investment schedule than previously contemplated.

In April 2012, Ameren Illinois submitted to the ICC an update filing under IEIMA based on 2011 recoverable costs and expected net plant additions for 2012. In December 2012, the ICC issued an order approving an Ameren Illinois electric delivery service revenue requirement of $764 million, which is a $15 million decrease in the revenue requirement allowed in the ICC initial filing order. The rates became effective on January 1, 2013, and will be effective through the end of 2013. 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 2013.

Ameren Illinois will submit to the ICC, during the second quarter of 2013, an update filing based on 2012 recoverable costs and expected net plant additions for 2013, which will determine rates that are effective during 2014.

Ameren Illinois' 2012 electric delivery service revenues were based on its 2012 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. The 2012 revenue requirement under the IEIMA's formula ratemaking framework was lower than the revenue requirement included in both the ICC's 2010 electric rate order and the ICC's September 2012 order related to Ameren Illinois' initial IEIMA filing. As a result, Ameren recorded a $55 million regulatory liability with a corresponding decrease in electric revenues to represent its estimate of the probable decrease in electric delivery service revenues expected to be approved by the ICC in December 2013 to provide Ameren Illinois recovery of all prudently and reasonably incurred costs and an earned rate of return on common equity for 2012. Any decrease in electric delivery service revenues approved by the ICC in December 2013 will be refunded to customers during 2014 with interest pursuant to the provisions of the IEIMA.

In December 2012, the ICC approved Ameren Illinois' advanced metering infrastructure deployment plan, which outlines how Ameren Illinois will comply with the IEIMA requirement to spend $360 million on smart grid assets over ten years on a cost-beneficial basis to its electric customers. The plan targets the second quarter of 2014 to begin installation of smart meters.

2013 Natural Gas Delivery Service Rate Case

On January 25, 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service by $50 million. The 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 requesting an increase in the percentage of costs to be recovered through a fixed non-volumetric customer charge from 80% to 85% for all residential customers and most commercial customers.

A decision by the ICC in this proceeding is required by December 2013. Ameren Illinois cannot predict the level of any delivery service rate changes the ICC may approve, when any rate changes may go into effect, 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. 

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ATXI Transmission Project

ATXI's Illinois Rivers project is a MISO-approved project that involves building a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. In 2012, ATXI made a filing with the ICC requesting a certificate of public convenience and necessity and project approval. A decision is expected by the ICC in 2013. A certificate of public convenience and necessity is required before ATXI can proceed with right-of-way acquisition.

Federal

Electric Transmission Investment

In May 2011, FERC approved transmission rate incentives for the Illinois Rivers project, which is being developed by ATXI. In December 2011, MISO approved the Illinois Rivers project as well as the Spoon River and Mark Twain projects. The total investment in these three MISO-approved projects is expected to be more than $1.3 billion between 2013 to 2019. These projects are primarily located in Illinois and Missouri.

In February 2012, FERC approved ATXI's request for a forward-looking rate calculation with an annual revenue requirement reconciliation, as well as ATXI's request for implementation of the incentives FERC approved in its May 2011 order for the Illinois Rivers project. In November 2012, FERC approved transmission rate incentives for the Spoon River project and the Mark Twain project. FERC also approved a forward-looking rate calculation with an annual revenue requirement reconciliation for Ameren Illinois' electric transmission business.

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 by $11 million. 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. A FERC decision is expected in 2013. Ameren has recorded $8 million in “Current regulatory liabilities” on its consolidated balance sheet as of December 31, 2012, for its estimate of the refund due to wholesale customers relating to billings from March 2011 through December 2012 based on the administrative law judge's initial decision.

Ameren Illinois Electric Transmission Rate Refund

On July 19, 2012, FERC issued an order approving 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. After reviewing the FERC order and its calculation of the impact on electric transmission formula rates, Ameren Illinois concluded that no refund was warranted. Several wholesale customers filed a protest with FERC regarding Ameren's conclusion that no refund is warranted. 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 and the amount could be estimated.

FERC Order - MISO Charges

Ameren Missouri and Ameren Illinois, as well as other MISO participants, have filed complaints with FERC with respect to the FERC’s March 2007 order involving the reallocation of certain MISO operational costs among MISO participants retroactive to 2005. Subsequently, FERC has issued a series of orders related to the applicability and the implementation of the order, which in some cases have conflicted with previous orders.

In May 2009, FERC changed the effective date for refunds such that certain operational costs would be allocated among MISO market participants beginning November 2008, instead of August 2007. In June 2009, Ameren Missouri and Ameren Illinois filed a request for rehearing. The rehearing request is pending.

In June 2009, FERC issued an order dismissing rehearing requests of a November 2008 order and waiving refunds of amounts billed that were included in the MISO charge, under the assumption that there was a rate mismatch for the period April 2006 through November 2007. Ameren Missouri and Ameren Illinois filed a request for rehearing in July 2009. This rehearing request is pending.

Ameren Missouri and Ameren Illinois do not believe that the ultimate resolution of these proceedings will have a material effect on their results of operations, financial position, or liquidity.

Ameren Missouri Power Purchase Agreement with Entergy

Beginning in 2005, FERC issued a series of orders addressing a complaint filed in 2001 by the Louisiana Public Service Commission (LPSC) against Entergy Arkansas, Inc. (Entergy) and certain of its affiliates. The complaint alleged unjust and unreasonable cost allocations. As a result of the FERC orders, Entergy began billing Ameren Missouri in 2007 for additional charges under a 165-megawatt power purchase agreement, and Ameren Missouri paid those charges. Additional charges continued during the remainder of the term of the power purchase agreement, which expired August 31, 2009. In May 2012, FERC issued an order upholding its January 2010 ruling that Entergy should not have included additional charges to Ameren Missouri under the power purchase agreement. Pursuant

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to the order, in June 2012, Entergy paid Ameren Missouri $31 million, with $24 million recorded as a reduction to “Purchased power” expense and $5 million for interest recorded as “Miscellaneous income” in the consolidated statement of income (loss), and the remaining $2 million recorded as an offset to the FAC under-recovered regulatory asset for the amount refundable to customers. The amount of the Entergy refund recorded to the FAC regulatory asset related to the period when the FAC was effective and, therefore, such costs were previously included in customer rates. As noted above, the MoPSC, in its December 2012 electric rate order, confirmed Ameren Missouri could retain the portion of the refund received from Entergy that related to the period prior to the implementation of the FAC. In July 2012, Entergy filed an appeal of FERC's January 2010 and May 2012 orders to the United States Court of Appeals for the District of Columbia. In December 2012, the Court of Appeals dismissed Entergy's appeal as premature because an Entergy motion seeking clarification or rehearing of the May 2012 order remains pending before FERC. It is unknown when FERC may act on the pending Entergy motion.

The LPSC appealed FERC’s orders regarding LPSC’s complaint against Entergy Services, Inc. to the United States Court of Appeals for the District of Columbia. In April 2008, that court ordered further FERC proceedings regarding LPSC’s complaint. The court ordered FERC to explain its previous denial of retroactive refunds and the implementation of prospective charges. FERC’s decision on remand of the retroactive impact of these issues could have a financial impact on Ameren Missouri. Ameren Missouri is unable to predict how FERC will respond to the court’s decisions. Ameren Missouri estimates that it could incur an additional expense of up to $25 million if FERC orders retroactive application for the years 2001 to 2005. Ameren Missouri believes that the likelihood of incurring any expense is not probable, and therefore no liability has been recorded as of December 31, 2012.

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 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 investment funds for only one small modular reactor design, which was not the Westinghouse design, but also stated that additional investment funds would be awarded during 2013. Westinghouse continues to pursue investment funds from the DOE.

If Westinghouse is awarded DOE's small modular reactor investment funds, Ameren Missouri will seek 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 does not obligate Ameren Missouri to build a small modular reactor at the Callaway site; however, it does 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. Ameren Missouri expects its incremental investment to obtain the small modular reactor COL to be minimal due to several factors, including the company's capitalized investments in new nuclear energy center development of $69 million as of December 31, 2012, the DOE investment funds that would help support the COL application, and Ameren Missouri's agreement with Westinghouse. If the DOE does not approve Westinghouse's application for the 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.

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 was made.

Pumped-storage Hydroelectric Energy Center Relicensing

In June 2008, Ameren Missouri filed a relicensing application with FERC to operate its Taum Sauk pumped-storage hydroelectric energy center for another 40 years. The existing FERC license expired on June 30, 2010. On July 2, 2010, Ameren Missouri received a license extension that allows Taum Sauk to continue operations until FERC issues a new license. FERC is reviewing the relicensing application. A FERC order is expected in 2013 or 2014. Ameren Missouri cannot predict the ultimate outcome of FERC's review of the application.

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Regulatory Assets and Liabilities

In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, Ameren Missouri and Ameren Illinois defer certain costs pursuant to actions of regulators or based on the expected ability to recover such costs in rates charged to customers. Ameren Missouri and Ameren Illinois also defer certain amounts because of actions of regulators or because of the expectation that such amounts will be returned to customers in future rates. The following table presents Ameren’s regulatory assets and regulatory liabilities at December 31, 2012, and 2011:

	2012		2011
Current regulatory assets:
Under-recovered FAC(a)(b)	$	145	$	83
Under-recovered Illinois electric power costs(a)(c)	—		4
Under-recovered PGA(a)(c)	12		8
MTM derivative losses(d)	90		120
Total current regulatory assets	$	247	$	215
Noncurrent regulatory assets:
Pension and postretirement benefit costs(e)	$	772	$	878
Income taxes(f)	235		239
Asset retirement obligations(g)	5		6
Callaway costs(a)(h)	44		48
Unamortized loss on reacquired debt(a)(i)	181		47
Recoverable costs - contaminated facilities(j)	248		102
MTM derivative losses(d)	135		100
SO2 emission allowances sale tracker(k)	2		6
Storm costs(l)	9		16
Demand-side costs(a)(m)	73		70
Reserve for workers’ compensation liabilities(n)	12		13
Credit facilities fees(o)	6		10
Employee separation costs(p)	2		6
Common stock issuance costs(q)	7		10
Construction accounting for pollution control equipment(a)(r)	23		25
Other(s)	32		27
Total noncurrent regulatory assets	$	1,786	$	1,603
Current regulatory liabilities:
Over-recovered FAC(t)	$	—	$	12
Over-recovered Illinois electric power costs(c)	58		64
Over-recovered PGA(c)	15		9
MTM derivative gains(u)	19		46
Wholesale distribution refund(v)	8		2
Total current regulatory liabilities	$	100	$	133
Noncurrent regulatory liabilities:
Income taxes(w)	$	46	$	48
Removal costs(x)	1,347		1,269
Asset retirement obligation(g)	80		29
MTM derivative gains(u)	2		82
Bad debt rider(y)	12		10
Pension and postretirement benefit costs tracker(z)	23		38
Energy efficiency rider(aa)	20		24
IEIMA revenue requirement reconciliation(ab)	55		—
Other(ac)	4		2
Total noncurrent regulatory liabilities	$	1,589	$	1,502

(a) These assets earn a return.

(b) Under-recovered fuel costs for periods from June 2010 through December 2012. Specific accumulation periods aggregate the under-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from customers that occurs over the next eight months.

(c) Costs under- or over-recovered from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral.

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(d) Deferral of commodity-related derivative MTM losses. The December 31, 2011 balance included the MTM losses on financial contracts entered into by Ameren Illinois with Marketing Company, which expired in December 2012.

(e) These costs are being amortized in proportion to the recognition of prior service costs (credits), transition obligations (assets), and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 11 - Retirement Benefits for additional information.

(f) Offset to certain deferred tax liabilities for expected recovery of future income taxes when paid. See Note 13 - Income Taxes for amortization period.

(g) Recoverable or refundable removal costs for AROs at our rate-regulated operations, including net realized and unrealized gains and losses related to the nuclear decommissioning trust fund investments. See Note 1 - Summary of Significant Accounting Policies - Asset Retirement Obligations.

(h) Ameren Missouri’s Callaway energy center operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the energy center's current operating license which expires in 2024.

(i) Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued.

(j) The recoverable portion of accrued environmental site liabilities, primarily collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of actual expenditures. See Note 15 - Commitments and Contingencies for additional information.

(k) A regulatory tracking mechanism for gains on sales of SO₂ emission allowances, net of SO₂ premiums incurred under the terms of coal procurement contracts, plus any SO₂ discounts received under such contracts, as approved in a MoPSC order. The MoPSC’s May 2010 electric rate order discontinued any future deferrals under this tracking mechanism. The MoPSC’s December 2012 rate order approved the amortization of these costs through December 2014.

(l) Actual storm costs in a test year that exceed the MoPSC staff’s normalized storm costs for rate purposes. As approved by the December 2012 MoPSC electric rate order, the 2006, 2007, and 2008 storm costs are being amortized through December 2014. As approved by the May 2010 MoPSC electric rate order, the 2009 storm costs are being amortized through June 2015.

(m) Demand-side costs, including the costs of developing, implementing and evaluating customer energy efficiency and demand response programs. Costs incurred from May 2008 through September 2008 are being amortized over a 10-year period that began in March 2009. Costs incurred from October 2008 through December 2009 are being amortized over a six-year period that began in July 2010. Costs incurred from January 2010 through February 2011 are being amortized over a six-year period that began in August 2011. Costs incurred from March 2011 through July 2012 are being amortized over a six-year period that began in January 2013. The amortization period for the costs incurred after July 2012 will be determined in a future Ameren Missouri electric rate case.

(n) Reserve for workers’ compensation claims. The period of recovery will depend on the timing of actual expenditures.

(o) Ameren Missouri’s costs incurred to enter into and maintain the 2012 Ameren Missouri Credit Agreement. These costs are being amortized over five years, beginning in November 2012. These costs are being amortized to construction work in progress, which will be subsequently depreciated when assets are placed into service.

(p) Costs incurred for voluntary and involuntary separation programs. The 2009 Ameren Missouri-related costs are being amortized over two years, beginning in January 2013, as approved by the December 2012 MoPSC electric rate order. The 2009 Ameren Illinois-related costs are being amortized over three years, beginning in May 2010, as approved by the April 2010 ICC electric and natural gas rate order.

(q) The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to recover its portion of Ameren’s September 2009 common stock issuance costs. These costs are being amortized over five years, beginning in July 2010.

(r) The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution control equipment at its Sioux energy center until the cost of that equipment was placed in customer rates. The amortization of these costs will be over the expected life of the Sioux energy center.

(s) The Ameren Illinois total includes Ameren Illinois Merger integration and optimization costs, which are amortized over four years, beginning in January 2012. The Ameren Illinois total includes costs related to delivery service rate cases. The 2012 natural gas rate case costs are being amortized over a two-year period that began in January 2012. The electric rate case costs for the IEIMA initial rate filing are being amortized over a three-year period that began in January 2012. The Ameren Illinois total also includes a portion of the unamortized debt fair value adjustment recorded upon Ameren's acquisition of IP. This portion is being amortized over the remaining life of the related debt, beginning with the expiration of the electric rate freeze in Illinois on January 1, 2007. At Ameren Missouri, the balance primarily includes cost associated with the retirement of renewable energy credits and solar rebates to fulfill its renewable energy portfolio requirement. Costs incurred from January 2010 through July 2012 are being amortized over three years, beginning January 2013. The amortization period for the costs incurred after July 2012 will be determined in a future Ameren Missouri electric rate case.

(t) Over-recovered fuel costs from March 2009 through September 2009 as ordered by the MoPSC in April 2011. Customer refunds concluded in 2012. Specific accumulation periods aggregate the over-recovered costs over four months, any related adjustments occur over the following four months, and then recovery from customers occurs over the next eight months.

(u) Deferral of commodity-related derivative MTM gains.

(v) Estimated refund to wholesale electric customers. See 2011 Wholesale Distribution Rate Case above.

(w) Unamortized portion of investment tax credit and federal excess deferred taxes. See Note 13 - Income Taxes for amortization period.

(x) Estimated funds collected for the eventual dismantling and removal of plant from service, net of salvage value, upon retirement related to our rate-regulated operations.

(y) A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by Ameren Illinois under GAAP and the level of such costs included in electric and natural gas rates. The over-recovery relating to 2010 was refunded to customers from June 2011 through May 2012. The over-recovery relating to 2011 is being refunded to customers from June 2012 through May 2013. The over-recovery relating to 2012 will be refunded to customers from June 2013 through May 2014.

(z) A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri under GAAP and the level of such costs built into rates. For periods prior to August 2012, the MoPSC's December 2012 electric rate order directed the amortization to occur over five years, beginning in January 2013. For periods after August 2012, the amortization period will be determined in a future Ameren Missouri electric rate case.

(aa) A regulatory tracking mechanism that allows Ameren Illinois to recover its electric and natural gas costs associated with developing, implementing, and evaluating customer energy efficiency and demand response programs. This over-recovery will be refunded to customers over the following 12 months after the plan year.

(ab) The difference between Ameren Illinois' 2012 revenue requirement calculated under the IEIMA's performance-based formula ratemaking framework, and the revenue requirement included in customer rates for 2012. Subject to ICC approval, this liability will be refunded to customers in 2014.

(ac) Balance primarily includes an Ameren Missouri liability relating to its 2010 property tax refund. The MoPSC's December 2012 electric rate order directed a refund to customers over a two-year period, beginning in January 2013.

Ameren Missouri and Ameren Illinois continually assess the recoverability of their regulatory assets. Under current accounting standards, regulatory assets are charged to earnings when it is no longer probable that such amounts will be recovered through future revenues. To the extent that payments of regulatory liabilities are no longer probable, the amounts are credited to earnings.

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NOTE 3 - PROPERTY AND PLANT, NET

The following table presents Ameren's property and plant, net, at December 31, 2012, and 2011:

	Ameren(a)
2012
Property and plant, at original cost:
Electric	$	20,942
Natural gas	1,854
	22,796
Less: Accumulated depreciation and amortization	8,346
	14,450
Construction work in progress:
Nuclear fuel in process	317
Other	581
Property and plant, net	$	15,348
2011
Property and plant, at original cost:
Electric	$	20,098
Natural gas	1,751
	21,849
Less: Accumulated depreciation and amortization	7,868
	13,981
Construction work in progress:
Nuclear fuel in process	255
Other	612
Property and plant, net	$	14,848

(a) Amounts include two electric generation CTs under two separate capital lease agreements. The gross asset value of those agreements was $228 million and $229 million at December 31, 2012, and 2011, respectively. The total accumulated depreciation associated with the two CTs was $52 million and $52 million at December 31, 2012, and 2011, respectively. In addition, Ameren has investments in debt securities, which are classified as held-to-maturity, related to the two CTs from the city of Bowling Green and Audrain County. As of December 31, 2012, and 2011, the carrying value of these debt securities was $304 million and $309 million, respectively.

The following table provides accrued capital expenditures at December 31, 2012, 2011, and 2010, which represent noncash investing activity excluded from the statements of cash flows:

2012	$	103
2011	92
2010	70

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, and drawings under committed bank credit agreements, or commercial paper issuances.

2012 Credit Agreements

On November 14, 2012, Ameren entered into the $1 billion 2012 Missouri Credit Agreement. The 2010 Missouri Credit Agreement was terminated when the 2012 Missouri Credit Agreement when into effect. Also on November 14, 2012, Ameren entered into the $1.1 billion 2012 Illinois Credit Agreement. The 2010 Illinois Credit Agreement was terminated

when the 2012 Illinois Credit Agreement went into effect. These facilities cumulatively provide $2.1 billion of credit through November 14, 2017, which date is inclusive of the Ameren Missouri and Ameren Illinois borrowing sublimit extensions discussed below of the maturity date to November 14, 2017, and which may be extended with the agreement of the lenders, subject to the terms of such agreements, for two additional one-year periods. The facilities currently include 24 international, national, and regional lenders, with no lender providing more than $125 million of credit in aggregate.

In addition, the 2010 Genco Credit Agreement, under which Ameren was a borrower, was not renewed and was terminated contemporaneously with the effectiveness of the 2012 Credit Agreements.

The obligations of each borrower under the respective 2012 Credit Agreements to which it is a party are several and not joint, and, except under limited circumstances relating to expenses and indemnities, the obligations of Ameren Missouri and Ameren Illinois under the respective 2012 Credit Agreements are not guaranteed by Ameren or any other subsidiary of Ameren. The maximum aggregate amount available to each borrower under each facility is shown in the following table (such amount being such borrower's "Borrowing Sublimit"):

	2012 Missouri Credit Agreement		2012 Illinois Credit Agreement
Ameren	$	500	$	300
Ameren Missouri	800		(a)
Ameren Illinois	(a)		$	800

(a) Not applicable.

Ameren has the option to seek additional commitments from existing or new lenders to increase the total facility size of the 2012 Credit Agreements up to the following maximum amounts: 2012 Missouri Credit Agreement - $1.2 billion; and 2012 Illinois Credit Agreement - $1.3 billion. Each of the 2012 Credit Agreements will mature and expire with respect to Ameren on November 14, 2017, unless extended as described above. Borrowing Sublimits of Ameren Missouri and Ameren Illinois under the applicable 2012 Credit Agreements will mature and expire on November 13, 2013, subject to extension thereof on a 364-day basis, as requested by the borrower and approved by the lenders, or for a longer period upon receipt of any and all required federal or state regulatory approvals, as permitted under the 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement, but in no event later than November 14, 2017. Ameren Missouri and Ameren Illinois intend to seek regulatory approval to extend the maturity dates of their respective Borrowing Sublimit under the 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement to November 14, 2017. If and when such regulatory approvals are received, no lender approval will be required to effect the extensions. The principal amount of each revolving loan owed by a borrower under any of the 2012 Credit Agreements to which it is a party will be due and payable no later than the final maturity date relating to such borrower under such 2012 Credit Agreements.

The obligations of all borrowers under the 2012 Credit

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Agreements are unsecured. Loans are available on a revolving basis under each of the 2012 Credit Agreements and may be repaid and, subject to satisfaction of the conditions to borrowing, reborrowed from time to time. At the election of each borrower, the interest rates on such loans will be the alternate base rate ("ABR") plus the margin applicable to the particular borrower and/or the Eurodollar rate plus the margin applicable to the particular borrower. The applicable margins will be determined by the borrower's long-term unsecured credit ratings or, if no such ratings are then in effect, the borrower's corporate/issuer ratings then in effect. Letters of credit in an aggregate undrawn face amount not to exceed 25% of the applicable aggregate commitment under the respective 2012 Credit Agreements are also available for issuance for the account of the borrowers thereunder (but within the $2.1 billion overall combined facility borrowing limitations of the 2012 Credit Agreements).

The borrowers will use the proceeds from any borrowings under the 2012 Credit Agreements for general corporate

purposes, including working capital, commercial paper liquidity support, loan funding under the Ameren money pool arrangements or other short-term intercompany loan arrangements, or paying fees and expenses incurred in connection with the 2012 Credit Agreements.

The 2012 Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren's commercial paper programs. Any of the 2012 Credit Agreements are available to Ameren to support borrowings under Ameren's commercial paper program, subject to borrowing sublimits. The 2012 Missouri Credit Agreement is available to support issuances under Ameren Missouri's commercial paper program, and the 2012 Illinois Credit Agreement is available to support issuances under Ameren Illinois' commercial paper program. As of December 31, 2012, based on letters of credit issued under the 2012 Credit Agreements, the aggregate amount of credit capacity available to Ameren (parent) at December 31, 2012, was $2.09 billion.

The following table summarizes the borrowing activity and relevant interest rates under the 2010 Missouri Credit Agreement, which terminated on November 14, 2012, for the years ended December 31, 2012, and 2011 and excludes issued letters of credit. Ameren, Ameren Missouri and Ameren Illinois did not borrow under the 2012 Credit Agreements from November 14, 2012, through December 31, 2012.

2010 Missouri Credit Agreement ($800 million) (Terminated)	Ameren (Parent)			Ameren Missouri			Total
2012
Average daily borrowings outstanding during 2012(a)	$	—		$	1		$	1
Outstanding credit facility borrowings at period end	—			—			—
Weighted-average interest rate during 2012(a)	—		%	4.15		%	4.15		%
Peak credit facility borrowings during 2012(a)	$	—		$	50		$	50
Peak interest rate during 2012	—		%	4.15		%	4.15		%
2011
Average daily borrowings outstanding during 2011	$	105		$	—		$	105
Outstanding credit facility borrowings at period end	—			—			—
Weighted-average interest rate during 2011	2.30		%	—			2.30		%
Peak credit facility borrowings during 2011	$	340		$	—		$	340
Peak interest rate during 2011	4.30		%	—			4.30		%

(a) Calculated through termination date.

Neither Ameren nor Ameren Illinois borrowed under the 2010 Illinois Credit Agreement during the years ended December 31, 2012, and 2011, respectively.

Commercial Paper

At December 31, 2012, Ameren did not have any commercial paper outstanding. At December 31, 2011, Ameren had $148 million of commercial paper outstanding. During the years ended December 31, 2012, and 2011, Ameren had average daily commercial paper balances outstanding of $49 million and $311 million with a weighted-average interest rate of 0.92% and 0.87%, respectively. The peak amounts of short-term commercial paper outstanding during the years ended December 31, 2012, and 2011, were $229 million and $435 million, respectively. The peak interest rate during the years ended December 31, 2012, and 2011, was 1.25% and 1.46%, respectively.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants.    

The 2012 Credit Agreements contain conditions to borrowings and issuances of letters of credit similar to those contained in the 2010 Credit Agreements, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation, and the absence of any notice of any violation, liability or requirement under any environmental laws that could have a material adverse effect), and obtaining required regulatory authorizations. In addition, solely as it relates

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to borrowings under the 2012 Illinois Credit Agreement, it is a condition for any such borrowing that, at the time of and after giving effect to such borrowing, the borrower not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation.

The 2012 Credit Agreements also contain nonfinancial covenants similar to those contained in the 2010 Credit Agreements, 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 requires Ameren 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 December 31, 2012, the ratio of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2012 Credit Agreements, was 51% for Ameren. 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 of2.0 to 1.0, 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 December 31, 2012 was 5.0 to 1.0. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2012 Credit Agreement.

The 2012 Credit Agreements contain default provisions. The default provisions in the 2012 Credit Agreements apply separately to each borrower, provided, however, that a default of Ameren Missouri or Ameren Illinois under the applicable 2012 Credit Agreement will also be deemed to constitute a default of Ameren under such agreement. Defaults include a cross-default to a default of such borrower under any other agreement covering outstanding indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and nonmaterial subsidiaries) in excess of $50 million in the aggregate (including under the other 2012 Credit Agreement). However, under the default provisions of the 2012 Credit Agreements, any default of Ameren under any such 2012 Credit Agreements that results solely from a default of Ameren Missouri or Ameren Illinois thereunder does not result in a cross-default of Ameren under the other 2012 Credit Agreement. Further, the 2012 Credit Agreement default provisions provide that an Ameren default under any of the 2012 Credit Agreements does not trigger a default by Ameren Missouri or Ameren Illinois.

None of the Ameren Companies' credit agreements or financing arrangements contain credit rating triggers that would cause a default or acceleration of repayment of outstanding balances. Management believes that the Ameren Companies were in compliance with the provisions and covenants of their credit agreements at December 31, 2012.

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 may participate in the utility money pool only as a lender. 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 rate for borrowing under the utility money pool for the year ended December 31, 2012, was 0.13%. There were no utility money pool borrowings during the year ended December 31, 2011.

Non-state-regulated Subsidiaries

Ameren (parent), 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 16 - 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

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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 rate for borrowing under the non-state-regulated subsidiary money pool for the year ended December 31, 2012, was 0.61% (2011 - 0.77%).

Unilateral Borrowing Agreement

In addition, a unilateral borrowing agreement exists among Ameren, Ameren Illinois, and Ameren Services, which enables

Ameren Illinois to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by Ameren Illinois under the unilateral borrowing agreement and the utility money pool agreement, together with any outstanding Ameren Illinois external credit facility borrowings or commercial paper issuances, may not exceed $500 million, pursuant to authorization from the ICC. Ameren Illinois is not currently borrowing under the unilateral borrowing agreement. Ameren Services is responsible for the operation and administration of the unilateral borrowing agreement.

NOTE 5 - LONG-TERM DEBT AND EQUITY FINANCINGS

The following table presents Ameren's long-term debt outstanding, including maturities due within one year, as of December 31, 2012, and 2011:

	2012			2011
Ameren (Parent):
8.875% Senior unsecured notes due 2014	$	425		$	425
Less: Unamortized discount and premium	(1		)	(1		)
Long-term debt, net	$	424		$	424
Ameren Missouri:
Senior secured notes:(a)
5.25% Senior secured notes due 2012	$	—		$	173
4.65% Senior secured notes due 2013	200			200
5.50% Senior secured notes due 2014	104			104
4.75% Senior secured notes due 2015	114			114
5.40% Senior secured notes due 2016	260			260
6.40% Senior secured notes due 2017	425			425
6.00% Senior secured notes due 2018(b)	179			250
5.10% Senior secured notes due 2018	199			200
6.70% Senior secured notes due 2019(b)	329			450
5.10% Senior secured notes due 2019	244			300
5.00% Senior secured notes due 2020	85			85
5.50% Senior secured notes due 2034	184			184
5.30% Senior secured notes due 2037	300			300
8.45% Senior secured notes due 2039(b)	350			350
3.90% Senior secured notes due 2042(b)	485			—
Environmental improvement and pollution control revenue bonds:
1992 Series due 2022(c)(d)	47			47
1993 5.45% Series due 2028(e)	44			44
1998 Series A due 2033(c)(d)	60			60
1998 Series B due 2033(c)(d)	50			50
1998 Series C due 2033(c)(d)	50			50
Capital lease obligations:
City of Bowling Green capital lease (Peno Creek CT) through 2022	64			69
Audrain County capital lease (Audrain County CT) due 2023	240			240
Total long-term debt, gross	4,013			3,955
Less: Unamortized discount and premium	(7		)	(5		)
Less: Maturities due within one year	(205		)	(178		)
Long-term debt, net	$	3,801		$	3,772

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	2012			2011
Ameren Illinois:
Senior secured notes:
8.875% Senior secured notes due 2013(f)(h)	$	150		$	150
6.20% Senior secured notes due 2016(f)	54			54
6.25% Senior secured notes due 2016(g)	75			75
6.125% Senior secured notes due 2017(g)(i)	250			250
6.25% Senior secured notes due 2018(g)(i)	144			337
9.75% Senior secured notes due 2018(g)(i)	313			400
2.70% Senior secured notes due 2022(g)(i)	400			—
6.125% Senior secured notes due 2028(g)	60			60
6.70% Senior secured notes due 2036(g)	61			61
6.70% Senior secured notes due 2036(f)	42			42
Environmental improvement and pollution control revenue bonds:
6.20% Series 1992B due 2012	—			1
2000 Series A 5.50% due 2014	—			51
5.90% Series 1993 due 2023(j)	32			32
5.70% 1994A Series due 2024(k)	36			36
1993 Series C-1 5.95% due 2026(l)	35			35
1993 Series C-2 5.70% due 2026(l)	8			8
1993 Series B-1 due 2028(d)(l)	17			17
5.40% 1998A Series due 2028(k)	19			19
5.40% 1998B Series due 2028(k)	33			33
Fair-market value adjustments	4			5
Total long-term debt, gross	1,733			1,666
Less: Unamortized discount and premium	(6		)	(8		)
Less: Maturities due within one year	(150		)	(1		)
Long-term debt, net	$	1,577		$	1,657
Ameren consolidated long-term debt, net	$	5,802		$	5,853

(a) These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Missouri first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2042.

(b) Ameren Missouri has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its first mortgage bonds. Ameren Missouri has also agreed to prevent a first mortgage bond release date from occurring as long as any of the 8.45% senior secured notes due 2039 and any of the 3.90% senior secured notes due 2042 remain outstanding.

(c) These bonds are secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri's senior secured notes. The bonds are also backed by an insurance guarantee policy.

(d) Interest rates, and periods during which such rates apply, vary depending on our selection of defined rate modes. Maximum interest rates could range up to 18% depending on the series of bonds. The average interest rates for 2012 and 2011 were as follows:

	2012		2011
Ameren Missouri 1992 Series	0.30	%	0.34	%
Ameren Missouri 1998 Series A	0.65	%	0.69	%
Ameren Missouri 1998 Series B	0.64	%	0.68	%
Ameren Missouri 1998 Series C	0.64	%	0.69	%
Ameren Illinois 1993 Series B-1	0.22	%	0.28	%

(e) These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage bond indenture and are secured by substantially all Ameren Missouri property and franchises. The bonds are callable at 100% of par value.

(f) These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the CILCO mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the CILCO first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2023.

(g) These notes are collaterally secured by mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the Ameren Illinois mortgage indenture remain outstanding. Redemption, purchase, or maturity of all mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Illinois mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the mortgage bond lien protection associated with these notes to fall away until 2028.

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(h) Ameren Illinois has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its CILCO first mortgage bonds, and therefore a CILCO first mortgage bond release date will not occur while any of such notes are outstanding.

(i) Ameren Illinois has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its Ameren Illinois mortgage bonds, and therefore an Ameren Illinois first mortgage bond release date will not occur as long as any of these notes are outstanding.

(j) These bonds are first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture and are secured by substantially all property of the former CILCO. The bonds are callable at 100% of par value.

(k) These bonds are mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture and are secured by substantially all property of the former IP and CIPS. The bonds are callable at 100% of par value. The bonds are also backed by an insurance guarantee policy.

(l) The bonds are callable at 100% of par value.

The following table presents Ameren's aggregate maturities of long-term debt, including current maturities, at December 31, 2012:

	Ameren (Parent)(a)		Ameren Missouri(a)		Ameren Illinois(a)(b)		Ameren Consolidated
2013	$	—	$	205	$	150	$	355
2014	425		109		—		534
2015	—		120		—		120
2016	—		266		129		395
2017	—		431		250		681
Thereafter	—		2,882		1,200		4,082
Total	$	425	$	4,013	$	1,729	$	6,167

(a) Excludes unamortized discount and premium of $1 million, $7 million, and $6 million at Ameren (Parent), Ameren Missouri, and Ameren Illinois, respectively.

(b) Excludes $4 million related to Ameren Illinois’ long-term debt fair-market value adjustments, which are being amortized to interest expense over the remaining life of the debt.

All classes of Ameren Missouri’s and Ameren Illinois’ preferred stock are entitled to cumulative dividends and have voting rights. Preferred stock not subject to mandatory redemption of Ameren's subsidiaries was included in "Noncontrolling Interests" on Ameren's consolidated balance sheet. The following table presents the outstanding preferred stock of Ameren Missouri and Ameren Illinois that is not subject to mandatory redemption. The preferred stock is redeemable, at the option of the issuer, at the prices shown below as of December 31, 2012, and 2011:

		Redemption Price(per share)			2012		2011
Ameren Missouri:
Without par value and stated value of $100 per share, 25 million shares authorized
$3.50 Series	130,000 shares	$	110.00		$	13	$	13
$3.70 Series	40,000 shares	104.75			4		4
$4.00 Series	150,000 shares	105.625			15		15
$4.30 Series	40,000 shares	105.00			4		4
$4.50 Series	213,595 shares	110.00		(a)	21		21
$4.56 Series	200,000 shares	102.47			20		20
$4.75 Series	20,000 shares	102.176			2		2
$5.50 Series A	14,000 shares	110.00			1		1
Total					$	80	$	80
Ameren Illinois:
With par value of $100 per share, 2 million shares authorized
4.00% Series	144,275 shares	$	101.00		$	14	$	14
4.08% Series	45,224 shares	103.00			5		5
4.20% Series	23,655 shares	104.00			2		2
4.25% Series	50,000 shares	102.00			5		5
4.26% Series	16,621 shares	103.00			2		2
4.42% Series	16,190 shares	103.00			2		2
4.70% Series	18,429 shares	103.00			2		2
4.90% Series	73,825 shares	102.00			7		7
4.92% Series	49,289 shares	103.50			5		5
5.16% Series	50,000 shares	102.00			5		5
6.625% Series	124,273.75 shares	100.00			12		12
7.75% Series	4,542 shares	100.00			1		1
Total					$	62	$	62
Total Ameren(b)					$	142	$	142

(a) In the event of voluntary liquidation, $105.50.

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(b) Preferred stock not subject to mandatory redemption of Ameren's subsidiaries was included in "Noncontrolling Interests" on Ameren's consolidated balance sheet.

Ameren has 100 million shares of $0.01 par value preferred stock authorized, with no shares outstanding.

Ameren

Ameren filed a Form S-3 registration statement with the SEC in June 2011, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common

stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions. In 2012, Ameren shares were purchased in the open market for DRPlus and its 401(k) plan. Under DRPlus and its 401(k) plan, Ameren issued 2.2 million and 3.0 million shares of common stock in 2011 and 2010, respectively, which were valued at $65 million and $80 million for the respective years.

Ameren Missouri

On September 11, 2012, Ameren Missouri issued $485 million principal amount of 3.90% senior secured notes due September 15, 2042, with interest payable semiannually on March 15 and September 15 of each year, beginning March 15, 2013. These notes are secured by first mortgage bonds. Ameren Missouri received net proceeds of $478 million. The proceeds were used, together with other available cash, to provide the funds necessary to complete Ameren Missouri's tender offer on September 20, 2012, including the payment of interest and all related fees and expenses, and to retire the $173 million principal amount 5.25% senior secured notes that matured in September 2012.

On September 20, 2012, Ameren Missouri completed its tender offer to purchase for cash its outstanding 6.00% senior secured notes due 2018, 6.70% senior secured notes due 2019, 5.10% senior secured notes due 2018, and 5.10% senior secured notes due 2019. Any notes that were not tendered and purchased in the tender offer remain outstanding and continue to be obligations of Ameren Missouri. The following table sets forth the aggregate principal amount of each series of notes repurchased, along with certain other items of the tender offer:

Senior Secured Notes	Principal Amount Repurchased		Premium Plus Accrued and Unpaid Interest(a)		Principal Amount Outstanding After Tender Offer
6.00% senior secured notes due 2018	$	71	$	19	$	179
6.70% senior secured notes due 2019	121		35		329
5.10% senior secured notes due 2018	1		(b)		199
5.10% senior secured notes due 2019	56		12		244

(a) The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $485 million3.90% senior secured notes due 2042.

(b) Amount is less than $1 million.

Ameren Illinois

On August 20, 2012, Ameren Illinois issued $400 million principal amount of 2.70% senior secured notes due September 1, 2022, with interest payable semiannually on March 1 and September 1 of each year, beginning March 1, 2013. These notes are secured by first mortgage bonds. Ameren Illinois received net proceeds of $397 million. The proceeds were used, together with other available cash, to provide the funds necessary to complete Ameren Illinois' tender offer on August 27, 2012, including the payment of interest and all related fees and expenses, and to redeem all $51 million principal amount of 5.50% pollution control revenue bonds at par value plus accrued interest.

On August 27, 2012, Ameren Illinois completed its tender offer to purchase for cash its outstanding 9.75% senior secured notes due 2018 and 6.25% senior secured notes due 2018. Any notes that were not tendered and purchased in the tender offer remain outstanding and continue to be obligations of Ameren Illinois. The following table sets forth the aggregate principal amount of each series of notes repurchased, along with certain other items of the tender offer:

Senior Secured Notes	Principal Amount Repurchased		Premium Plus Accrued and Unpaid Interest(a)		Principal Amount Outstanding After Tender Offer
9.75% senior secured notes due 2018	$	87	$	36	$	313
6.25% senior secured notes due 2018	194		47		144

(a) The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $400 million2.70% senior secured notes due 2022.

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In November 2012, $1 million of Ameren Illinois' 6.20% Series 1992B Pollution Control revenue bonds matured and were retired.

Indenture Provisions and Other Covenants

Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions but would restrict the companies’ ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios and bonds and preferred stock issuable as of December 31, 2012, at an assumed interest rate of 6% and dividend rate of 7%.

	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	4.6	$	4,056		>2.5	122.8	$	2,351
Ameren Illinois	>2.0	7.1	3,439		(d)	>1.5	2.8	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.

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 nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, 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 December 31, 2012, Ameren Illinois’ ratio of common stock equity to total capitalization was 57%.

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 December 31, 2012, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future. See Note 14 - Related Party Transactions with New AER for Ameren (parent) guarantees on behalf of its subsidiaries.

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NOTE 6 - OTHER INCOME AND EXPENSES

The following table presents the components of "Other Income and Expenses" in Ameren's consolidated statement of income (loss) for the years ended December 31, 2012, 2011, and 2010:

	2012			2011		2010
Ameren:
Miscellaneous income:
Interest and dividend income	$	4	(a)	$	3	$	4
Interest income on industrial development revenue bonds	28			28		28
Allowance for equity funds used during construction	36			34		52
Other	2			3		4
Total miscellaneous income	$	70		$	68	$	88
Miscellaneous expense:
Donations	$	24	(b)	$	8	$	19
Other	13			15		13
Total miscellaneous expense	$	37		$	23	$	32

(a) Includes interest income relating to a 2012 refund of charges included in an expired power purchase agreement with Entergy. See Note 2 - Rate and Regulatory Matters for additional information.

(b) Includes Ameren Illinois' one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and $1 million annual donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois' 2012 participation in the formula ratemaking process.

NOTE 7 - DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, electricity, and uranium. Such price fluctuations may cause the following:

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

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

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

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

The following table presents open gross commodity contract volumes by commodity type as of December 31, 2012, and 2011:

	Quantity (in millions, except as indicated)
Commodity	Accrual & NPNS Contracts(a)		Other Derivatives(b)		Derivatives That Qualify for Regulatory Deferral(c)
	2012	2011	2012	2011	2012	2011
Coal (in tons)	96	116	(d)	(d)	(d)	(d)
Fuel oils (in gallons)(e)	(d)	(d)	(d)	(d)	70	53
Natural gas (in mmbtu)	20	50	—	9	147	193
Power (in megawatthours)	24	12	2	1	23	21
Renewable energy credits(f)	15	16	(d)	(d)	(d)	(d)
Uranium (pounds in thousands)	5,142	5,553	(d)	(d)	446	148

(a) Accrual contracts include commodity contracts that do not qualify as derivatives. As of December 31, 2012, these contracts ran through December 2017, March 2015, September 2024, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively.

(b) As of December 31, 2012, these contracts ran through December 2014 for power.

(c) As of December 31, 2012, these contracts ran through October 2015, March 2017, May 2032, and September 2014 for fuel oils, natural gas, power, and uranium, respectively.

(d) Not applicable.

(e) Fuel oils consist of heating and crude oil.

(f) A renewable energy credit is created for every megawatthour of renewable energy generated. Ameren contracts include renewable energy credits from solar and wind-generated power.

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

If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine 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 consolidated statement of income (loss) in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the consolidated statement of income (loss).

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 consolidated statement of income (loss) 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 (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. The Ameren Companies did not elect to adopt this guidance for any eligible commodity contracts.

The following table presents the carrying value and balance sheet location of all derivative instruments as of December 31, 2012, and 2011:

	Balance Sheet Location	2012		2011
Derivative assets not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	Other current assets	$	8	$	17
	Other assets	4		6
Natural gas	Other current assets	1		3
	Other assets	1		1
Power	Other current assets	14		30
	Other assets	1		77
	Total assets	$	29	$	134
Derivative liabilities not designated as hedging instruments(a)
Commodity contracts:
Fuel oils	MTM derivative liabilities	$	2	$	1
	Other deferred credits and liabilities	2		—
Natural gas	MTM derivative liabilities	64		103
	Other deferred credits and liabilities	45		92
Power	MTM derivative liabilities	25		18
	Other deferred credits and liabilities	90		8
Uranium	MTM derivative liabilities	1		—
	Other deferred credits and liabilities	1		1
	Total liabilities	$	230	$	223

(a) Includes derivatives subject to regulatory deferral.

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The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments deferred in regulatory assets or regulatory liabilities as of December 31, 2012, and 2011:

	2012			2011
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Fuel oils derivative contracts(a)	$	4		$	19
Natural gas derivative contracts(b)	(107		)	(191		)
Power derivative contracts(c)	(99		)	81
Uranium derivative contracts(d)	(2		)	(1		)

(a) Represents net gains on fuel oils derivative contracts. These contracts are a partial hedge of transportation costs for coal through October 2015 as of December 31, 2012. Current gains deferred as regulatory liabilities include $4 million as of December 31, 2012. Current losses deferred as regulatory assets include $1 million as of December 31, 2012.

(b) Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through March 2017 as of December 31, 2012. Current gains deferred as regulatory liabilities include $1 million as of December 31, 2012. Current losses deferred as regulatory assets include $64 million as of December 31, 2012.

(c) Represents net losses associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 as of December 31, 2012. Current gains deferred as regulatory liabilities include $14 million as of December 31, 2012. Current losses deferred as regulatory assets include $24 million as of December 31, 2012.

(d) Represents net losses on uranium derivative contracts. These contracts are a partial hedge of uranium requirements through September 2014 as of December 31, 2012. Current losses deferred as regulatory assets include $1 million as of December 31, 2012, respectively.

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

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

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into groupings according to the primary business in which each engages. The following table presents by groupings the maximum exposure, as of December 31, 2012, and 2011, if counterparty groups were to fail completely to perform on contracts. The maximum exposure is based on the gross fair value of financial instruments, including accrual and NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.

	Affiliates		Coal Producers		Commodity Marketing Companies		Electric Utilities		Financial Companies		Municipalities/ Cooperatives		Total
2012	$	—	$	—	$	2	$	3	$	15	$	3	$	23
2011	$	1	$	35	$	85	$	4	$	27	$	4	$	156

The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held. The Ameren Companies held no cash from counterparties based on contractual rights under agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements as of December 31, 2012, and 2011. Other collateral used to reduce exposure consisted of letters of credit in the amount of $1 million and $1 million held at December 31, 2012, and 2011, respectively. The following table presents the potential loss after consideration of the application of master trading and netting agreements and collateral held as of December 31, 2012, and 2011:

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	Affiliates		Coal Producers		Commodity Marketing Companies		Electric Utilities		Financial Companies		Municipalities/ Cooperatives		Total
2012	$	—	$	—	$	1	$	1	$	10	$	3	$	15
2011	$	1	$	35	$	85	$	3	$	22	$	4	$	150

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of December 31, 2012, and 2011, 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 December 31, 2012, or 2011, 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)
2012	$	226	$	61	$	155
2011	$	322	$	104	$	211

(a) Prior to consideration of master trading and netting agreements and including NPNS and accrual contract exposures.

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

Other Derivatives

The following table represents the net change in market value associated with derivatives not designated as hedging instruments for the years ended December 31, 2012, and 2011:

	Location of Gain (Loss) Recognized in Income	Gain (Loss) Recognized in Income
		2012		2011
Natural gas (generation)	Operating Expenses - Fuel	$	—	$	(1	)

Derivatives Subject to Regulatory Deferral

The following table represents the net change in market value associated with derivatives that qualify for regulatory deferral for the years ended December 31, 2012, and 2011:

	Gain (Loss) Recognized In Regulatory Liabilities or Regulatory Assets
	2012			2011
Fuel oils	$	(15	)	$	—
Natural gas	84			(26		)
Power	(180		)	80
Uranium	(1		)	(3		)
Total	$	(112	)	$	51

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

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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 comprises 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 primarily 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 derivatives contracts are valued based upon the use of multiple forward prices provided by third parties. The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments.

Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors. Note 17 - Impairment and Other Charges describes Ameren's use of significant unobservable inputs, which are Level 3 inputs, to estimate the fair value of Merchant Generation's long-lived assets.

We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the period ended December 31, 2012:

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	Fair Value							Range [Weighted
	Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Average]
Level 3 Derivative asset and liability - commodity contracts(a):
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
						Option model	Volatilities(%)(b)	7 - 27 [24]
Power(e)	14		(114		)	Discounted cash flow	Average bid/ask consensus peak and off-peak 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($/credit)(b)	5 - 7 [6]
Uranium	—		(2		)	Discounted cash flow	Average bid/ask consensus pricing($/pound)(b)	43 - 46 [44]

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

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

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

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

(e) Power valuations utilize visible third-party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand.

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. We recorded no gains or losses related to valuation adjustments for counterparty default risk in 2012, 2011, or 2010. The counterparty default risk liability valuation adjustment related to derivative contracts totaled $7 million and $4 million, as of December 31, 2012, and 2011, 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 December 31, 2012:

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		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:	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	$	269	$	144	$	22	$	435
Liabilities:	Derivative liabilities - commodity contracts(a):
	Fuel oils	1		—		3		4
	Natural gas	7		102		—		109
	Power	—		1		114		115
	Uranium	—		—		2		2
	Total	$	8	$	103	$	119	$	230

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

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

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The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2011:

		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:	Derivative assets - commodity contracts(a):
	Fuel oils	$	20	$	—	$	3	$	23
	Natural gas	2		—		2		4
	Power	—		1		106		107
	Total derivative assets - commodity contracts	$	22	$	1	$	111	$	134
	Nuclear decommissioning trust fund(b):
	Cash and cash equivalents	3		—		—		3
	Equity securities:
	U.S. large capitalization	234		—		—		234
	Debt securities:
	Corporate bonds	—		44		—		44
	Municipal bonds	—		1		—		1
	U.S. treasury and agency securities	—		65		—		65
	Asset-backed securities	—		10		—		10
	Other	—		1		—		1
	Total nuclear decommissioning trust fund	$	237	$	121	$	—	$	358
	Total	$	259	$	122	$	111	$	492
Liabilities:	Derivative liabilities - commodity contracts(a):
	Fuel oils	$	1	$	—	$	—	$	1
	Natural gas	19		—		176		195
	Power	—		1		25		26
	Uranium	—		—		1		1
	Total	$	20	$	1	$	202	$	223

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

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

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The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2012, and 2011:

	Net Derivative Commodity Contracts
	2012				2011
Fuel oils:
Beginning balance at January 1	$	3			$	30
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities	(1		)		19
Total realized and unrealized gains (losses)	(1		)		19
Purchases	7				4
Sales	(3		)		(1		)
Settlements	(2		)		(30		)
Transfers into Level 3	1				—
Transfers out of Level 3	—				(19		)
Ending balance at December 31	$	5			$	3
Change in unrealized gains (losses) related to assets/liabilities held at December 31	$	(1	)		$	(11	)
Natural gas:
Beginning balance at January 1	$	(174	)		$	(148	)
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities	(27		)		(115		)
Total realized and unrealized gains (losses)	(27		)		(115		)
Purchases	—				1
Sales	—				(1		)
Settlements	16				89
Transfers out of Level 3	185				—
Ending balance at December 31	$	—			$	(174	)
Change in unrealized gains (losses) related to assets/liabilities held at December 31	$	—			$	(78	)
Power:
Beginning balance at January 1	$	81			$	19
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities	(175		)		55
Total realized and unrealized gains (losses)	(175		)		55
Purchases	21				30
Sales	(1		)		(1		)
Settlements	(22		)		(22		)
Transfers into Level 3	—				(1		)
Transfers out of Level 3	(4		)		1
Ending balance at December 31	$	(100	)		$	81
Change in unrealized gains (losses) related to assets/liabilities held at December 31	$	(175	)	(a)	$	(25	)
Uranium:
Beginning balance at January 1	$	(1	)		$	2
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities	(2		)		(3		)
Total realized and unrealized gains (losses)	(2		)		(3		)
Purchases	—				(1		)
Settlements	1				1
Ending balance at December 31	$	(2	)		$	(1	)
Change in unrealized gains (losses) related to assets/liabilities held at December 31	$	(1	)		$	—

(a) The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois swap contracts, which expire in May 2032.

Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers out of Level 3 into Level 2 for natural gas derivatives were due to management previously using broker quotations to estimate the fair value of natural gas contracts and changing to estimates based upon exchange closing prices without significant unobservable adjustments in the first quarter 2012. Estimates of fair value based on exchange closing prices are deemed to be a more accurate approximation of natural gas prices. Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and

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Level 3 for fuel oils were primarily caused by changes in availability of financial trades observable on electronic exchanges between the period ended December 31, 2012 and the previous reporting period ended December 31, 2011. Any reclassifications are reported as transfers out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the years ended December 31, 2012, and 2011, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the years ended December 31, 2012, and 2011:

	2012			2011
Derivative commodity contracts:
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils	$	1		$	—
Transfers out of Level 3 / Transfers into Level 1 - Fuel oils	—			(19		)
Transfers out of Level 3 / Transfers into Level 2 - Natural gas	185			—
Transfers into Level 3 / Transfers out of Level 2 - Power	—			(1		)
Transfers out of Level 3 / Transfers into Level 2 - Power	(4		)	1
Net fair value of Level 3 transfers	$	182		$	(19	)

See Note 11 - Retirement Benefits for the fair value hierarchy tables detailing Ameren’s pension and postretirement plan assets as of December 31, 2012, as well as a table summarizing the changes in Level 3 plan assets during 2012. See Note 17 - Impairment and Other Charges for the fair value hierarchy discussion related to Ameren's impairment charges.

The Ameren Companies’ carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. Ameren's carrying amounts of investments in debt securities related to the two CTs from the city of Bowling Green and Audrain County approximate fair value. These investments are classified as held-to-maturity. These investments are considered Level 2 in the fair value hierarchy as they are valued based on similar market transactions. Short-term borrowings, which are composed of Ameren issued commercial paper, also approximate fair value because of their short-term nature. Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy.

The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock at December 31, 2012, and 2011:

	2012				2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt and capital lease obligations (including current portion)	$	6,157	$	7,110	$	6,032	$	6,961
Preferred stock(a)	142		123		142		92

(a) Preferred stock along with the noncontrolling interest of EEI is recorded in "Noncontrolling Interests" on the consolidated balance sheet.

NOTE 9 - NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS

Ameren Missouri has investments in debt and equity securities that are held in a trust fund for the purpose of funding the decommissioning of its Callaway energy center. We have classified these investments as available for sale, and we have recorded all such investments at their fair market value at December 31, 2012, and 2011. See Note 10 - Callaway Energy Center for additional information.

Investments in the nuclear decommissioning trust fund have a target allocation of 60% to 70% in equity securities, with the balance invested in debt securities.

The following table presents proceeds from the sale and maturities of investments in Ameren Missouri’s nuclear decommissioning trust fund and the gross realized gains and

losses resulting from those sales for the years ended December 31, 2012, 2011, and 2010:

	2012		2011		2010
Proceeds from sales and maturities	$	384	$	199	$	256
Gross realized gains	6		5		5
Gross realized losses	2		4		4

Net realized and unrealized gains and losses are deferred and recorded as regulatory assets or regulatory liabilities on Ameren’s consolidated balance sheet. This reporting is consistent with the method used to account for the decommissioning costs recovered in rates. Gains or losses associated with assets in the trust fund could result in lower or higher funding requirements for decommissioning costs, which are expected to be reflected in electric rates paid by Ameren Missouri’s customers. See Note 2 - Rate and Regulatory Matters.

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The following table presents the costs and fair values of investments in debt and equity securities in Ameren Missouri’s nuclear decommissioning trust fund at December 31, 2012, and 2011:

Security Type	Cost			Gross Unrealized Gain		Gross Unrealized Loss		Fair Value
2012
Debt securities	$	133		$	8	(a)		$	141
Equity securities	145			130		11		264
Cash	1			—		—		1
Other(b)	2			—		—		2
Total	$	281		$	138	$	11	$	408
2011
Debt securities	$	114		$	7	(a)		$	121
Equity securities	145			101		12		234
Cash	3			—		—		3
Other(b)	(1		)	—		—		(1		)
Total	$	261		$	108	$	12	$	357

(a) Amount less than $1 million.

(b) Represents payables relating to pending security purchases, net of receivables related to pending security sales and interest receivables.

The following table presents the costs and fair values of investments in debt securities in Ameren Missouri’s nuclear decommissioning trust fund according to their contractual maturities at December 31, 2012:

	Cost		Fair Value
Less than 5 years	$	78	$	79
5 years to 10 years	32		35
Due after 10 years	23		27
Total	$	133	$	141

We have unrealized losses relating to certain available-for-sale investments included in our decommissioning trust fund, recorded as regulatory assets as discussed above. Decommissioning will not occur until the operating license for our nuclear energy center expires. Ameren Missouri submitted a license extension application to the NRC to extend the Callaway energy center’s operating license to 2044. The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in Ameren Missouri's nuclear decommissioning trust fund. They are aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position at December 31, 2012:

	Less than 12 Months				12 Months or Greater				Total
	Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses
Debt securities	$	17	$ (a)		$ (a)		$ (a)		$	17	$ (a)
Equity securities	7		1		14		10		21		11
Total	$	24	$	1	$	14	$	10	$	38	$	11

(a) Amount less than $1 million.

NOTE 10 - CALLAWAY ENERGY CENTER

Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. Under the NWPA, Ameren and other utilities that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established the fee that these utilities pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatthour generated 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 utilities have entered into standard

contracts with the federal government. The government, represented by the DOE, is responsible for implementing these provisions of 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.

Although both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, the federal government has acknowledged since at least 1994 that it would not meet that deadline. The federal government is not currently predicting when it will begin to meet its disposal obligation. Ameren Missouri has sufficient installed capacity at its Callaway energy center to store the spent

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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 utilities’ 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 by 2026, to characterize the site and to design and to license the repository by 2042, and to begin operation by 2048.

In view of the federal government's efforts to terminate the Yucca Mountain program, the Nuclear Energy Institute, a number of individual utilities, and the National Association of Regulatory Utility Commissioners sued the DOE in the United States Court of Appeals for the District of Columbia Circuit seeking the suspension of the one mill nuclear waste fee, alleging that the DOE failed to undertake an appropriate fee adequacy review reflecting the current unsettled state of the nuclear waste program. In a June 2012 decision, the court ruled that DOE's fee adequacy review was legally inadequate and remanded the matter to the DOE. Although the court ruled it has the power to direct the DOE to suspend the fee, the court decided that it was premature to do so. Instead, the court ordered the DOE to provide within six months a revised assessment of the amount that should be collected. On January 19, 2013, the DOE issued the revised assessment required by the court. The DOE determined that “neither insufficient nor excess revenues are being collected” and it proposed no adjustment to the one mill nuclear waste fee.

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 DOE's failure to begin to dispose of the utilities' spent nuclear fuel and fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners have also 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 a payment to Ameren Missouri of $11 million for spent fuel storage and related costs through 2010 and, thereafter, annual payment of such costs after they are incurred through 2013 or any other mutually agreed extension. As a result of this settlement agreement, Ameren recorded a pretax reduction of $2 million and $2 million to its “Operating Expenses - Depreciation and amortization” and “Operating Expenses - Other operations and maintenance” expense line items, respectively, on its consolidated statement of income (loss) for the year ended December 31, 2011. Ameren reduced its property and plant net assets by $7 million for the year ended December 31, 2011. Ameren Missouri received the 2011 cost reimbursement of $1 million and reduced its property and plant net assets by this amount in 2012. In March 2013, Ameren Missouri plans to submit approximately $5 million of 2012 costs to the DOE for reimbursement under the settlement agreement.

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 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 generic environmental impact statement and a final rule to address the court's ruling. The NRC also stated that a site-specific analysis of these issues could be conducted in rare circumstances. 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.

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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 has 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 2012, 2011, and 2010. 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. The last cost study and funding analysis were filed with the MoPSC in September 2011. In October 2012, the MoPSC issued an order approving the stipulation and agreement between Ameren Missouri and the MoPSC staff that maintained the current rate of deposits to the trust fund and the rate of return assumptions used in the analysis. 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 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 consolidated balance sheet. 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 2 - Rate and Regulatory Matters for additional information related to the Callaway energy center.

NOTE 11 - RETIREMENT BENEFITS

The primary objective of the Ameren pension and postretirement benefit plans is to provide eligible employees with pension and postretirement health care and life insurance

benefits. Ameren offers defined benefit pension and postretirement benefit plans covering substantially all of its employees. Ameren uses a measurement date of December 31 for its pension and postretirement benefit plans. Ameren’s qualified pension plan is the Ameren Retirement Plan. Ameren also has an unfunded non-qualified pension plan, the Ameren Supplemental Retirement Plan, which is available for certain management employees and retirees to provide a supplemental benefit when their qualified pension plan benefits are reduced to comply with Internal Revenue Code limitations. Ameren’s other postretirement plans are the Ameren Retiree Medical Plan and the Ameren Group Life Insurance Plan. Separately, EEI employees and retirees participate in EEI’s single-employer pension and other postretirement plans. EEI’s pension plan is the Revised Retirement Plan for Employees of Electric Energy, Inc. EEI’s other postretirement plans are the Group Insurance Plan for Management Employees of Electric Energy, Inc. and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. Nonaffiliated Ameren companies do not participate in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Under this agreement, Ameren will retain the pension and postretirement benefits 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. These obligations are estimated at $40 million and are included in "Current liabilities of discontinued operations" on Ameren's consolidated balance sheet. In addition to these obligations, IPH will acquire the estimated $15 million asset at December 31, 2012, relating to the overfunded status of one of EEI's postretirement plans. This asset is included in "Current assets of discontinued operations" on Ameren's consolidated balance sheet. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information. The disclosures in this note only reflect continuing operations. Therefore, the impacts of the EEI plans are not reflected.

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Ameren recognizes the under-funded status of its pension and postretirement plans as a liability on its consolidated balance sheet, with offsetting entries to accumulated OCI and regulatory assets, in accordance with authoritative accounting guidance. The following table presents the funded status of our pension and postretirement benefit plans as of December 31, 2012, and 2011. It also provides the amounts included in regulatory assets and accumulated OCI at December 31, 2012, and 2011, that have not been recognized in net periodic benefit costs.

	2012						2011
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
Accumulated benefit obligation at end of year	$	3,829		(a)			$	3,553		(a)
Change in benefit obligation:
Net benefit obligation at beginning of year	$	3,764		$	1,145		$	3,366		$	1,036
Service cost	81			22			73			20
Interest cost	166			47			175			54
Plan amendments(b)	—			—			(16		)	—
Participant contributions	—			16			—			18
Actuarial (gain) loss	240			(10		)	335			71
Benefits paid	(200		)	(69		)	(169		)	(63		)
Early retiree reinsurance program receipt	(a)			2			(a)			3
Federal subsidy on benefits paid	(a)			4			(a)			6
Net benefit obligation at end of year	4,051			1,157			3,764			1,145
Change in plan assets:
Fair value of plan assets at beginning of year	2,814			836			2,664			735
Actual return on plan assets	385			104			223			8
Employer contributions	128			45			96			129
Federal subsidy on benefits paid	(a)			4			(a)			6
Early retiree reinsurance program receipt	(a)			2			(a)			3
Participant contributions	—			16			—			18
Benefits paid	(200		)	(69		)	(169		)	(63		)
Fair value of plan assets at end of year	3,127			938			2,814			836
Funded status - deficiency	924			219			950			309
Accrued benefit cost at December 31	$	924		$	219		$	950		$	309
Amounts recognized in the consolidated balance sheet consist of:
Current liability	$	3		$	2		$	3		$	3
Noncurrent liability	921			217			947			306
Net liability recognized	$	924		$	219		$	950		$	309
Amounts recognized in regulatory assets consist of:
Net actuarial loss	$	699		$	103		$	734		$	177
Prior service cost (credit)	(6		)	(24		)	(7		)	(28		)
Transition obligation	—			—			—			2
Amounts (pretax) recognized in accumulated OCI consist of:
Net actuarial loss	65			5			54			5
Prior service cost (credit)	(14		)	(6		)	(16		)	(7		)
Total	$	744		$	78		$	765		$	149

(a) Not applicable.

(b) In 2011, Ameren’s pension plan was amended to adjust the calculation of the future benefit obligation of approximately 430 labor union-represented employees from a traditional, final pay formula to a cash balance formula.

The following table presents the assumptions used to determine our benefit obligations at December 31, 2012, and 2011:

	Pension Benefits				Postretirement Benefits
	2012		2011		2012		2011
Discount rate at measurement date	4.00	%	4.50	%	4.00	%	4.50	%
Increase in future compensation	3.50		3.50		3.50		3.50
Medical cost trend rate (initial)	—		—		5.00		5.50
Medical cost trend rate (ultimate)	—		—		5.00		5.00
Years to ultimate rate	0		0		0		1 year

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Ameren determines discount rate assumptions by identifying a theoretical settlement portfolio of high-quality corporate bonds sufficient to provide for a plan's projected benefit payments, pursuant to authoritative accounting guidance on the determination of discount rates used for defined benefit plan obligations. The settlement portfolio of bonds is selected from a pool of over 600 high-quality corporate bonds.  A single discount rate is then determined that results in a discounted value of the plan's benefit payments that equates to the market value of the selected bonds.

Funding

Pension benefits are based on the employees’ years of service and compensation. Ameren’s pension plan is funded in compliance with income tax regulations and federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plan at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at December 31, 2012, its investment performance in 2012, and its pension funding policy, Ameren expects to make annual contributions of $50 million to $150 million in each of the next five years, with aggregate estimated contributions of $525 million. These amounts are estimates. The estimates may change based on actual investment performance, changes in interest rates, changes in our assumptions, any pertinent changes in government regulations, and any voluntary contributions. Our funding policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.

The following table presents the cash contributions made to our defined benefit retirement plan and to our postretirement plans during 2012, 2011, and 2010:

Pension Benefits						Postretirement Benefits
2012		2011		2010		2012		2011		2010
$	128	$	96	$	81	$	45	$	129	$	36

Investment Strategy and Policies

Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. The investment committee, to the extent authority is delegated to it by the finance committee of Ameren’s board of directors, implements investment strategy and asset allocation guidelines for the plan assets. The investment committee includes members of senior management. The investment committee’s goals are twofold: first, to ensure that sufficient funds are available to provide the benefits at the time they are payable and second, to maximize total return on plan assets and minimize expense volatility consistent with its tolerance for risk. Ameren delegates investment management to specialists in each asset class. As appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. The investment committee regularly monitors manager performance and compliance with investment guidelines.

The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class were estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjusted the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns and for the effect of expenses paid from plan assets. Ameren will utilize an expected return on plan assets for its pension plan assets and postretirement plan assets of 7.50% and 7.25%, respectively, in 2013. No plan assets are expected to be returned to Ameren during 2013.

Ameren’s investment committee strives to assemble a portfolio of diversified assets that does not create a significant concentration of risks. The investment committee develops asset allocation guidelines between asset classes, and it creates diversification through investments in assets that differ by type (equity, debt, real estate, private equity), duration, market capitalization, country, style (growth or value) and industry, among other factors. The diversification of assets is displayed in the target allocation table below. The investment committee also routinely rebalances the plan assets to adhere to the diversification goals. The investment committee’s strategy reduces the concentration of investment risk; however, Ameren is still subject to overall market risk. The following table presents our target allocations for 2013 and our pension and postretirement plans’ asset categories as of December 31, 2012, and 2011.

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Asset Category	Target Allocation 2013	Percentage of Plan Assets at December  31,
		2012		2011
Pension Plan:
Cash and cash equivalents	0 - 5  %	2	%	2	%
Equity securities:
U.S. large capitalization	29 - 39	34		33	%
U.S. small and mid-capitalization	2 - 12	7		7	%
International and emerging markets	9 - 19	13		11	%
Total equity	50 - 60	54		51	%
Debt securities	35 - 45	39		42	%
Real estate	0 -   9	4		4	%
Private equity	0 -   4	1		1	%
Total		100	%	100	%
Postretirement Plans:
Cash and cash equivalents	0 - 10 %	4	%	4	%
Equity securities:
U.S. large capitalization	33 - 43	40	%	38	%
U.S. small and mid-capitalization	3 - 13	8	%	8	%
International	10 - 20	14	%	13	%
Total equity	55 - 65	62	%	59	%
Debt securities	30 - 40	34	%	37	%
Total		100	%	100	%

In general, the United States large capitalization equity investments are passively managed or indexed, whereas the international, emerging markets, United States small capitalization, and United States mid-capitalization equity investments are actively managed by investment managers. Debt securities include a broad range of fixed income vehicles. Debt security investments in high-yield securities, emerging market securities, and non-United States dollar-denominated securities are owned by the plans, but in limited quantities to reduce risk. Most of the debt security investments are under active management by investment managers. Real estate investments include private real estate vehicles; however, Ameren does not, by policy, hold direct investments in real estate property. Ameren’s investment in private equity funds consists of 10 different limited partnerships, with invested capital ranging from $0.1 million to $5 million each, which invest primarily in a diversified number of small United States-based companies. No further commitments may be made to private equity investments without approval by the finance committee of the board of directors. Additionally, Ameren’s investment committee allows investment managers to use derivatives, such as index futures, exchange traded funds, foreign exchange futures, and options, in certain situations, to increase or to reduce market exposure in an efficient and timely manner.

Fair Value Measurements of Plan Assets

Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 2012. The fair value of an asset is the amount that would be received upon sale in an orderly transaction between market participants at the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. The carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments. Investments traded in active markets on national or international securities exchanges are valued at closing prices on the last business day on or before the measurement date. Securities traded in over-the-counter markets are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Derivative contracts are valued at fair value, as determined by the investment managers (or independent third parties on behalf of the investment managers), who use proprietary models and take into consideration exchange quotations on underlying instruments, dealer quotations, and other market information. The fair value of real estate is based on annual appraisal reports prepared by an independent real estate appraiser.

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The following table sets forth, by level within the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the pension plan assets measured at fair value as of December 31, 2012:

	Quoted Prices in Active Markets for Identified Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Cash and cash equivalents	$	1		$	28	$	—	$	29
Equity securities:
U.S. large capitalization	83			1,007		—		1,090
U.S. small and mid-capitalization	235			—		—		235
International and emerging markets	134			301		—		435
Debt securities:
Corporate bonds	—			832		—		832
Municipal bonds	—			176		—		176
U.S. treasury and agency securities	—			250		—		250
Other	—			17		—		17
Real estate	—			—		118		118
Private equity	—			—		19		19
Derivative assets	—			—		—		—
Derivative liabilities	(1		)	—		—		(1		)
Total	$	452		$	2,611	$	137	$	3,200
Less: Medical benefit assets at December 31(a)								(102		)
Plus: Net receivables at December 31(b)								29
Fair value of pension plans assets at year end								$	3,127

(a) Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code (401(h) accounts) to fund a portion of the postretirement obligation.

(b) Receivables related to pending security sales, offset by payables related to pending security purchases.

The following table sets forth, by level within the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the pension plan assets measured at fair value as of December 31, 2011:

	Quoted Prices in Active Markets for Identified Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Cash and cash equivalents	$	—		$	30	$	—	$	30
Equity securities:
U.S. large capitalization	72			901		—		973
U.S. small and mid-capitalization	202			—		—		202
International and emerging markets	115			208		—		323
Debt securities:
Corporate bonds	—			794		—		794
Municipal bonds	—			176		—		176
U.S. treasury and agency securities	—			230		—		230
Other	—			23		—		23
Real estate	—			—		108		108
Private equity	—			—		23		23
Derivative assets	1			—		—		1
Derivative liabilities	(1		)	—		—		(1		)
Total	$	389		$	2,362	$	131	$	2,882
Less: Medical benefit assets at December 31(a)								(91		)
Plus: Net receivables at December 31(b)								23
Fair value of pension plans assets at year end								$	2,814

(a) Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code (401(h) accounts) to fund a portion of the postretirement obligation.

(b) Receivables related to pending security sales, offset by payables related to pending security purchases.

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The following table summarizes the changes in the fair value of the pension plan assets classified as Level 3 in the fair value hierarchy for each of the years ended December 31, 2012, and 2011:

	Beginning Balance at January 1,		Actual Return on Plan Assets Related to Assets Still Held at the Reporting Date			Actual Return on Plan Assets Related to Assets Sold During the Period		Purchases, Sales, and Settlements, net			Net Transfers into (out of) of Level 3		Ending Balance at December 31,
2012:
Real estate	$	108	$	7		$	—	$	3		$	—	$	118
Private equity	23		(7		)	8		(5		)	—		19
2011:
Real estate	$	98	$	10		$	—	$	—		$	—	$	108
Private equity	28		(10		)	11		(6		)	—		23

The following table sets forth, by level within the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the postretirement benefit plans assets measured at fair value as of December 31, 2012:

	Quoted Prices in Active Markets for Identified Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Cash and cash equivalents	$	83	$	—	$	—	$	83
Equity securities:
U.S. large capitalization	245		88		—		333
U.S. small and mid-capitalization	66		—		—		66
International	45		69		—		114
Debt securities:
Corporate bonds	—		88		—		88
Municipal bonds	—		91		—		91
U.S. treasury and agency securities	—		67		—		67
Asset-backed securities	—		18		—		18
Other	—		22		—		22
Total	$	439	$	443	$	—	$	882
Plus: Medical benefit assets at December 31(a)							102
Less: Net payables at December 31(b)							(46		)
Fair value of postretirement benefit plans assets at year end							$	938

(a) Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above.

(b) Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales.

The following table sets forth, by level within the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the postretirement benefit plans assets measured at fair value as of December 31, 2011:

	Quoted Prices in Active Markets for Identified Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Cash and cash equivalents	$	1	$	65	$	—	$	66
Equity securities:
U.S. large capitalization	206		78		—		284
U.S. small and mid-capitalization	57		—		—		57
International	38		56		—		94
Debt securities:
Corporate bonds	—		71		—		71
Municipal bonds	—		80		—		80
U.S. treasury and agency securities	—		69		—		69
Asset-backed securities	—		23		—		23
Other	—		34		—		34
Total	$	302	$	476	$	—	$	778
Plus: Medical benefit assets at December 31(a)							91
Less: Net payables at December 31(b)							(33		)
Fair value of postretirement benefit plans assets at year end							$	836

(a) Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above.

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(b) Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales.

Net Periodic Benefit Cost

The following table presents the components of the net periodic benefit cost of our pension and postretirement benefit plans during 2012, 2011, and 2010:

	Pension Benefits			Postretirement Benefits
2012
Service cost	$	81		$	22
Interest cost	166			47
Expected return on plan assets	(208		)	(56		)
Amortization of:
Transition obligation	—			2
Prior service cost	(3		)	(6		)
Actuarial loss	75			5
Net periodic benefit cost	$	111		$	14
2011
Service cost	$	73		$	20
Interest cost	175			54
Expected return on plan assets	(211		)	(50		)
Amortization of:
Transition obligation	—			2
Prior service cost	(1		)	(6		)
Actuarial loss	41			3
Net periodic benefit cost	$	77		$	23
2010
Service cost	$	65		$	18
Interest cost	181			58
Expected return on plan assets	(208		)	(51		)
Amortization of:
Transition obligation	—			2
Prior service cost	6			(6		)
Actuarial loss	18			—
Net periodic benefit cost	$	62		$	21

The current year expected return on plan assets is determined primarily by adjusting the prior-year market-related asset value for current year contributions, disbursements, and expected return, plus 25% of the actual return in excess of (or less than) expected return for the four prior years.

The estimated amounts that will be amortized from regulatory assets and accumulated OCI into net periodic benefit cost in 2013 are as follows:

	Pension Benefits			Postretirement Benefits
	Ameren			Ameren
Regulatory assets:
Prior service cost (credit)	$	(1	)	$	(4	)
Net actuarial loss	97			19
Accumulated OCI:
Prior service cost (credit)	(2		)	(1		)
Net actuarial loss	5			—
Total	$	99		$	14

Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting under the plan amendment. The net actuarial loss subject to amortization is amortized on a straight-line basis over 10 years.

The expected pension and postretirement benefit payments from qualified trust and company funds and the federal subsidy for postretirement benefits related to prescription drug benefits, which reflect expected future service, as of December 31, 2012, are as follows:

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	Pension Benefits				Postretirement Benefits
	Paid from Qualified Trust		Paid from Company Funds		Paid from Qualified Trust		Paid from Company Funds		Federal Subsidy
2013	$	229	$	3	$	58	$	2	$	3
2014	236		3		60		2		3
2015	239		3		62		2		4
2016	245		3		65		2		4
2017	248		3		68		2		4
2018 - 2022	1,279		13		384		11		19

The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2012, 2011, and 2010:

	Pension Benefits						Postretirement Benefits
	2012		2011		2010		2012		2011		2010
Discount rate at measurement date	4.50	%	5.25	%	5.75	%	4.50	%	5.25	%	5.75	%
Expected return on plan assets	7.75		8.00		8.00		7.50		7.75		8.00
Increase in future compensation	3.50		3.50		3.50		3.50		3.50		3.50
Medical cost trend rate (initial)	—		—		—		5.50		6.00		6.50
Medical cost trend rate (ultimate)	—		—		—		5.00		5.00		5.00
Years to ultimate rate	0		0		0		1 year		2 years		3 years

The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:

	Pension Benefits					Postretirement Benefits
	Service Cost and Interest Cost			Projected Benefit Obligation		Service Cost and Interest Cost			Postretirement Benefit Obligation
0.25% decrease in discount rate	$	(2	)	$	121	$	—		$	34
0.25% increase in salary scale	2			13		—			—
1.00% increase in annual medical trend	—			—		—			36
1.00% decrease in annual medical trend	—			—		(1		)	(34		)

Other

Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible employees at December 31, 2012. The plan allowed employees to contribute a portion of their compensation in accordance with specific guidelines. Ameren matched a percentage of the employee contributions up to certain limits. Ameren incurred costs of $28 million, $28 million, and $27 million in relation to the matching contribution for the years ended December 31, 2012, 2011, and 2010, respectively.

NOTE 12 - STOCK-BASED COMPENSATION

Ameren’s long-term incentive plan is available to for eligible employees, under Ameren's shareholder-approved 2006 Omnibus Incentive Compensation Plan (2006 Plan), which became effective May 2, 2006. The 2006 Plan provides for a maximum of 4 million common shares to be available for grant to eligible employees and directors. The 2006 Plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards.

A summary of nonvested shares at December 31, 2012, and changes during the year ended December 31, 2012, under the 2006 Plan are presented below:

	Performance Share Units
	Share Units		Weighted-average Fair Value per Unit
Nonvested at January 1, 2012	1,156,831		$	31.70
Granted(a)	717,151		35.68
Unearned or forfeited(b)	(477,928	)	32.04
Earned and vested(c)	(203,567	)	34.01
Nonvested at December 31, 2012	1,192,487		$	33.56

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2012 under the 2006 Plan.

(b) Includes share units granted in 2010 that were not earned based on performance provisions of the award grants.

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(c) Includes share units granted in 2010 that vested as of December 31, 2012, that were earned pursuant to the provisions of the award grants. Also includes share units that vested due to 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 recorded compensation expense of $22 million, $13 million, and $11 million for the years ended December 31, 2012, 2011, and 2010, respectively, and a related tax benefit of $8 million, $5 million and $4 million for the years ended December 31, 2012, 2011, and 2010, respectively. Ameren settled performance share units and restricted shares of $11 million, $4 million, and $2 million for the years ended December 31, 2012, 2011, and 2010. All outstanding restricted shares vested as of the end of 2011. There were no significant compensation costs capitalized related to the performance share units during the years ended December 31, 2012, 2011, and 2010. As of December 31, 2012, total compensation cost of $21 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 20 months.

Performance Share Units

Performance share units have been granted under the 2006 Plan. A share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, certain specified performance or market conditions have been met and the individual remains employed by Ameren. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals.

The fair value of each share unit awarded in January 2012 under the 2006 Plan was determined to be $35.68. That amount was based on Ameren's closing common share price of $33.13 at December 31, 2011, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren's total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2012. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.41%, volatility of 17% to 31% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.

The fair value of each share unit awarded in January 2011 under the 2006 Plan was determined to be $31.41. That amount was based on Ameren’s closing common share price of $28.19 at December 31, 2010, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2011. The simulations can produce a greater fair value for the share unit than the closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.08%,

volatility of 22% to 36% for the peer group, and Ameren’s attainment of three-year average earnings per share threshold during the performance period.

NOTE 13 - INCOME TAXES

The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate for the years ended December 31, 2012, 2011, and 2010:

	2012		2011		2010
Statutory federal income tax rate:	35	%	35	%	35	%
Increases (decreases) from:
Depreciation differences	(1	)	(1	)	(3	)
Amortization of investment tax credit	(1	)	(1	)	(1	)
State tax	5		4		5
Reserve for uncertain tax positions	—		1		(1	)
Tax credits	—		(1	)	(1	)
Change in federal tax law(a)	—		—		2
Other permanent items(b)	(1	)	—		—
Effective income tax rate	37	%	37	%	36	%

(a) Relates to change in taxation of prescription drug benefits to retiree participants from the enactment in 2010 of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010.

(b) Permanent items are treated differently for book and tax purposes and primarily include nondeductible expense related to lobbying and stock issuance expenses.

The following table presents the components of income tax expense for the years ended December 31, 2012, 2011, and 2010:

	2012			2011			2010
Current taxes:
Federal	$	40		$	(6	)	$	3
State	9			(2		)	(1		)
Deferred taxes:
Federal	205			206			247
State	61			53			32
Deferred investment tax credits, amortization	(6		)	(6		)	(7		)
Total income tax expense	$	309		$	245		$	274

The Illinois corporate income tax rate increased from 7.3% to 9.5%, starting in January 2011. The tax rate is scheduled to decrease to 7.75% in 2015, and it is scheduled to return to 7.3% in 2025. This corporate income tax rate increase in Illinois increased current income tax expense in 2011 by $6 million. As a result of this corporate income tax rate increase, accumulated deferred tax balances were revalued, resulting in a decrease in deferred tax expense of $2 million in 2011.

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The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 2012, and 2011:

	2012			2011
Accumulated deferred income taxes, net liability (asset):
Plant related	$	3,512		$	3,162
Deferred intercompany tax gain/basis step-up	39			54
Regulatory assets, net	73			73
Deferred employee benefit costs	(323		)	(320		)
Purchase accounting	(27		)	(28		)
ARO	(17		)	(12		)
Other(a)	(251		)	(217		)
Total net accumulated deferred income tax liabilities	$	3,006		$	2,712

(a) Includes deferred tax assets related to net operating loss and tax credit carryforwards detailed in the table below.

The following table presents the components of deferred tax assets relating to net operating loss carryforwards and tax credit carryforwards at December 31, 2012:

	2012
Net operating loss carryforwards:
Federal(a)	$	173
State(b)	27
Total net operating loss carryforwards	$	200
Tax credit carryforwards:
Federal(c)	$	86
State(d)	25
State valuation allowance(e)	(2		)
Total tax credit carryforwards	$	109

(a) These will begin to expire in 2028.

(b) These will begin to expire in 2017.

(c) These will begin to expire in 2029.

(d) These will begin to expire in 2013.

(e) This balance increased by $1 million during 2012.

Uncertain Tax Positions

A reconciliation of the change in the unrecognized tax benefit balance during the years ended December 31, 2012, 2011, and 2010, is as follows:

	2012			2011			2010
Unrecognized tax benefits - beginning of year	$	148		$	246		$	135
Increases based on tax positions prior to current year	5			22			72
Decreases based on tax positions prior to current year	(13		)	(125		)	(38		)
Increases based on tax positions related to current year	17			17			77
Changes related to settlements with taxing authorities	—			(10		)	—
Decreases related to the lapse of statute of limitations	(1		)	(2		)	—
Unrecognized tax benefits - end of year	$	156		$	148		$	246
Total unrecognized tax benefits that, if recognized, would affect the effective tax rates	$	1		$	1		$	—

The Ameren Companies recognize interest charges (income) and penalties accrued on tax liabilities on a pretax basis as interest charges (income) or miscellaneous expense, respectively, in the statements of income.

A reconciliation of the change in the liability for interest on unrecognized tax benefits during the years ended December 31, 2012, 2011, and 2010, is as follows:

	2012		2011			2010
Liability for interest - beginning of year	$	5	$	17		$	8
Interest charges (income)	1		(11		)	9
Interest payment	—		(1		)	—
Liability for interest - end of year	$	6	$	5		$	17

As of December 31, 2012, 2011, and 2010, the Ameren Companies have accrued no amount for penalties with respect to unrecognized tax benefits.

In the second quarter of 2011, a final settlement for the years 2005 and 2006 was reached with the Internal Revenue Service. It resulted in a reduction in uncertain tax liabilities of $39 million. Ameren’s federal income tax returns for the years 2007 through 2010 are before the Appeals Office of the Internal

Revenue Service. Ameren’s federal income tax return for the year 2011 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 twelve months for the years 2007 through 2010. This settlement, primarily related to uncertain tax positions for capitalization versus currently deductible repair expense and research tax deductions, is expected to result in a decrease in uncertain tax benefits of approximately $143 million. 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 IRS Appeals Office settlement discussed above, would be material to their results of operations, financial position, or liquidity.

State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. The Ameren Companies do not

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currently have material state income tax issues under examination, administrative appeals, or litigation.

NOTE 14 - RELATED PARTY TRANSACTIONS WITH NEW AER

Ameren and its subsidiaries have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are eliminated in consolidation for Ameren’s financial statements. Below are the material related party agreements with New AER, with the exception of certain parent company guarantees not affiliated with New AER noted below.

Put Option Agreement and Guarantee

On March 28, 2012, Genco entered into a put option agreement with AERG. The put option gave Genco the option to sell to AERG all, but not less than all, of the Grand Tower, the Gibson City, and the Elgin gas-fired energy centers. If Genco exercised the put option, the purchase price for all three energy centers would be the greater of $100 million or the fair market value of the energy centers, as determined by three third-party appraisers in accordance with the terms of the agreement. Upon exercise of the put option, the $100 million minimum purchase price would be payable to Genco within one business day. If Genco exercised the put option, the closing of the sale of all three energy centers would be subject to the receipt of all necessary regulatory approvals. In exchange for entering into the put option agreement, Genco paid AERG a put option premium of $2.5 million.

The put option agreement required AERG to secure and maintain an Ameren guarantee of payment of contingent obligations under the agreement. Ameren and AERG entered into such a guarantee agreement on March 28, 2012. The guarantee shall remain in effect until either AERG or Ameren satisfies all of the payment obligations under the put option agreement, or until the put option agreement is terminated and no further payments are owed by AERG to Genco.

See Note 16 - Divestiture Transactions and Discontinued Operations for information regarding amendments to the put option agreement and Ameren guarantee, as well as the exercise of the put option, in 2013.

Electric Power Supply Agreements

Capacity Supply Agreements

Ameren Illinois, as an electric load-serving entity, must acquire capacity sufficient to meet its obligations to customers.

In 2009, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2009, through May 31, 2012. Marketing Company was among the winning suppliers in the capacity RFP process. In April 2009, Marketing Company contracted to supply a portion of Ameren

Illinois’ capacity requirements to Ameren Illinois for $4 million, $9 million, and $8 million for the 12 months ending May 31, 2010, 2011, and 2012, respectively.

In 2010, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2010, through May 31, 2013. Marketing Company was among the winning suppliers in the capacity RFP process. In April 2010, Marketing Company contracted to supply a portion of Ameren Illinois’ capacity requirements to Ameren Illinois for $1 million, $2 million, and $3 million for the 12 months ending May 31, 2011, 2012, and 2013, respectively.

During 2012, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2012, through May 31, 2015. Marketing Company was among the winning suppliers in the capacity RFP process. In April 2012, Marketing Company contracted to supply a portion of Ameren Illinois' capacity requirements for less than $1 million and $4 million for the 12 months ending May 31, 2013 and 2015, respectively.

Energy Swaps and Energy Products

Ameren Illinois, as an electric load-serving entity, must acquire energy sufficient to meet its obligations to customers.

In 2009, Ameren Illinois used a RFP process, administered by the IPA, to procure financial energy swaps from June 1, 2009, through May 31, 2011. Marketing Company was a winning supplier in the financial energy swap RFP process. In May 2009, Marketing Company entered into financial instruments that fixed the price that Ameren Illinois paid for approximately 80,000 megawatthours at approximately $48 per megawatthour during the 12 months ending May 31, 2010 and for approximately 89,000 megawatthours at approximately $48 per megawatthour during the 12 months ending May 31, 2011.

In 2010, Ameren Illinois used a RFP process, administered by the IPA, to procure financial energy swaps for the period from June 1, 2010, through May 31, 2013. Marketing Company was a winning supplier in the financial energy swap RFP process. In May 2010, Marketing Company entered into financial instruments that fixed the price that Ameren Illinois paid for approximately 924,000 megawatthours at approximately $33 per megawatthour during the 12 months ending May 31, 2011 and for approximately 296,000 megawatthours at approximately $40 per megawatthour during the 12 months ending May 31, 2012.

In 2011, Ameren Illinois used a RFP process administered by the IPA to procure energy products that will settle physically from June 1, 2011, through May 31, 2014. Marketing Company was a winning supplier in Ameren Illinois’ energy product RFP process. In May 2011, Marketing Company and Ameren Illinois entered into energy product agreements by which Marketing Company will sell and Ameren Illinois will purchase approximately 1,747,200 megawatthours at approximately $37 per megawatthour during the 12 months ending May 31, 2012, approximately 1,840,800 megawatthours at approximately $42 per megawatthour during the 12 months ending May 31, 2013,

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and approximately 650,000 megawatthours at approximately $42 per megawatthour during the 12 months ending May 31, 2014.

In February 2012, a rate stability procurement for energy products that will settle physically was administered by the IPA for the June 2013 through May 2017 period to meet certain requirements for purchased power related to the IEIMA. Marketing Company was a winning supplier in Ameren Illinois’ energy product procurement process. In February 2012, Marketing Company and Ameren Illinois entered into energy product agreements pursuant to which Marketing Company will sell and Ameren Illinois will purchase approximately 3,942,000 megawatthours at approximately $30 per megawatthour during the 12 months ending May 31, 2014, approximately 3,504,000 megawatthours at approximately $32 per megawatthour during the 12 months ending May 31, 2015, and approximately 1,317,600 megawatthours at approximately $34 per megawatthour during the 12 months ending May 31, 2016. The energy product agreements were based on around-the-clock prices.

Support Services Agreements

Ameren Services provides support services to its affiliates. The costs of support services, including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred. The shared services support agreement can be terminated with respect to a particular affiliate by the mutual agreement of Ameren Services and that affiliate or by either Ameren Services or that affiliate with 60 days notice before the end of a calendar year. Ameren has begun planning how it will to reduce, and ultimately eliminate AER's reliance on the support services agreement.

Gas Sales and Transportation Agreement

Under a gas transportation agreement, Genco acquires gas transportation service from Ameren Missouri. This agreement expires in February 2016.

Transmission Services Agreement

Under a transmission services agreement, Marketing Company acquires transmission services from Ameren Illinois and ATXI for certain retail and residential customers.

Collateral Postings

Under the terms of the Illinois power procurement agreements entered into through RFP processes administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Marketing Company, as a winning supplier in the RFP process, may be required to post collateral. As of December 31, 2012 and 2011, there were no collateral postings required of 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, 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. Beginning in June 2012, Marketing Company sold and Ameren Illinois purchased 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 December 31, 2012, Ameren Illinois' payable to Marketing Company for the purchase of trade receivables totaled $5 million. For the year ended December 31, 2012, Ameren Illinois purchased $35 million of trade receivables from Marketing Company at a discount of less than $1 million. Marketing Company's receivable from Ameren Illinois as well as Ameren Illinois' payable to Marketing Company are eliminated in the consolidated Ameren Corporation's financial statements.

Intercompany Sales

In 2012, Genco completed the sale of land for cash proceeds of $2 million to ATXI. Genco recognized a $2 million gain from the sale. Under authoritative accounting guidance for rate-regulated entities, the gain was not eliminated upon consolidation.

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 existing on Ameren's consolidated balance sheet.

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. 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

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up to 24 months after the closing. See Note 16 - Divestiture Transactions and Discontinued Operations.

At December 31, 2012, Ameren had a total of $354 million in guarantees outstanding, which included:

• $189 million related to Ameren's Merchant Generation segment, primarily for Marketing Company as support for physically and financially settled power transactions with its counterparties. The amounts above do not represent incremental consolidated Ameren obligations; rather, they represent Ameren parental guarantees of subsidiary obligations to third parties 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 December 31, 2012, which represents the total amount Ameren (parent) could be required to fund based on December 31, 2012 market prices.

• $100 million associated with the guarantee agreement between Ameren and AERG entered into on March 28, 2012, relating to the put option agreement between Genco and AERG. 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 from Ameren for the pending sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which was subject to FERC approval. In September 2013, Ameren paid Genco an additional $37 million based on the appraised value of these energy centers. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding the amended put option agreement and other transaction details.

• $50 million guarantee to MISO for all of Ameren's subsidiaries who are MISO market participants. Ameren's estimated exposure for obligations under transactions covered by this guarantee was $32 million at December 31, 2012, which represents the total amount Ameren (parent) could be required to fund based on December 31, 2012 market prices.

• $15 million related to requirements for asset transactions, leasing, and other service agreements. At December 31, 2012, Ameren estimated it had no exposure to any of these guarantees.

Additionally, at December 31, 2012, Ameren had issued letters of credit totaling $9 million as credit support to certain subsidiaries.

The related party transactions discussed above, with the exception of Genco's land sale to ATXI and the parent company guarantees, are eliminated in Ameren's consolidated financial statements. Ameren will have continuing transactions with New AER after the divestiture is complete that will not be eliminated in Ameren's consolidated financial statements. The following table presents the impact of these related party transactions, primarily based on the agreements discussed above, for the years ended December 31, 2012, 2011, and 2010.

Agreement	Income Statement Line Item		Amount
Ameren Missouri and Genco gas	Operating Revenues	2012	$	1
transportation agreement		2011	1
		2010	1
Ameren Illinois and ATXI transmission services agreement	Operating Revenues	2012	16
with Marketing Company		2011	11
		2010	10
Total Operating Revenues		2012	$	17
		2011	12
		2010	11
Ameren Illinois power supply agreements	Purchased Power	2012	$	311
with Marketing Company		2011	232
		2010	233
Ameren Illinois gas purchases from Genco	Gas Purchased for Resale	2012	$	—
		2011	—
		2010	1

NOTE 15 - COMMITMENTS AND CONTINGENCIES

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

See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 10 - Callaway Energy Center and Note 14 - Related Party Transactions with New AER in this report.

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Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at December 31, 2012. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.

Type and Source of Coverage	Maximum Coverages			Maximum Assessments
Public liability and nuclear worker liability:
American Nuclear Insurers	$	375		$	—
Pool participation	12,219		(a)	118		(b)
	$	12,594	(c)	$	118
Property damage:
Nuclear Electric Insurance Ltd.	$	2,750	(d)	$	23	(e)
Replacement power:
Nuclear Electric Insurance Ltd	$	490	(f)	$	9	(e)
Energy Risk Assurance Company	$	64	(g)	$	—

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

(b) Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.

(c) Limit of liability for each incident under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.

(d) Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.

(e) All Nuclear Electric Insurance Ltd. insured plants could be subject to assessments should losses exceed the accumulated funds from Nuclear Electric Insurance Ltd.

(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million.

(g) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 14 - Related Party Transactions with New AER for more information on this affiliate transaction.

The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective October 29, 2008. The next adjustment could occur during the fourth quarter of 2013. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by the Price-Anderson Act.

Losses resulting from terrorist attacks are covered under Nuclear Electric Insurance Ltd’s policies, subject to an industrywide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

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

Leases

We lease various facilities, office equipment, plant equipment, and rail cars under capital and operating leases. The following table presents our lease obligations at December 31, 2012:

	Total		2013		2014		2015		2016		2017		After 5 Years
Capital lease payments(a)	$	588	$	32	$	32	$	33	$	33	$	33	$	425
Less amount representing interest	284		27		27		27		27		27		149
Present value of minimum capital lease payments	$	304	$	5	$	5	$	6	$	6	$	6	$	276
Operating leases(b)	138		19		14		14		14		14		63
Total lease obligations	$	442	$	24	$	19	$	20	$	20	$	20	$	339

(a) See Properties under Part I, Item 2, and Note 3 - Property and Plant, Net of this report for additional information.

(b) Amounts related to certain land-related leases have indefinite payment periods. The annual obligation of $2 million for these items is included in the 2013 through 2017 columns, respectively.

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Ameren recorded total rental expense, included in operating expenses, of $33 million, $36 million, and $41 million for the years ended December 31, 2012, 2011, and 2010, respectively.

Other Obligations

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 December 31, 2012. Ameren’s purchased power obligations include Ameren Missouri's 102-megawatt power purchase agreement with a wind farm operator that expires in 2024 and 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 December 31, 2012, obligations related to IEIMA for Ameren Illinois, and obligations related to energy efficiency programs under the MEEIA as approved by the MoPSC's December 2012 electric rate order for Ameren Missouri. The order provides that, beginning in 2013, Ameren Missouri will invest approximately $147 million over three years for energy efficiency programs. See Note 2 - Rate and Regulatory Matters for additional information about the IEIMA and MEEIA.

	Coal		Natural Gas		Nuclear Fuel		Purchased Power(a)		Methane Gas		Other		Total
2013	$	620	$	327	$	36	$	421	$	3	$	156	$	1,563
2014	625		249		89		309		3		159		1,434
2015	614		136		87		164		4		117		1,122
2016	644		54		95		78		4		62		937
2017	676		34		78		55		5		50		898
Thereafter	245		105		277		687		99		246		1,659
Total	$	3,424	$	905	$	662	$	1,714	$	118	$	790	$	7,613

(a) The purchased power amounts includes Ameren Illinois' 20-year agreements for renewable energy credits that were entered into in December 2010 with various renewable energy suppliers. The agreements contain a provision that allows Ameren Illinois to reduce the quantity purchased in the event that Ameren Illinois would not be able to recover the costs associated with the renewable energy credits.

Previously, Ameren Illinois entered into an agreement to purchase approximately 15.5 billion cubic feet of synthetic natural gas annually over a 10-year period beginning in 2016 for its natural gas customers. The agreement was entered into pursuant to an Illinois law, that became effective August 2, 2011. Ameren Illinois' obligations under the agreement were contingent on the counterparty reaching certain milestones during the project development and the construction of the plant that was to produce the synthetic natural gas. The counterparty failed to meet certain milestones during 2012 and, accordingly, the contract was terminated.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities and natural gas storage, transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

In addition to existing laws and regulations, including the Illinois MPS that applies to AER's energy centers in Illinois, the EPA is developing environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren that operate coal-fired energy centers. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards for fine particulates, SO_2, and NO₂ 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; 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 has proposed CO₂ limits for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing 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 in August 2012. Although many details of these future regulations are unknown, the combined effects on Ameren of the new and proposed environmental regulations may result in significant capital expenditures and/or increased

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operating costs over the next five to ten years. 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 EPA's proposed regulation for CCR and the finalized MATS as of December 31, 2012. The estimates in the table below assume that CCR will continue to be regarded as nonhazardous. The estimates in the table below do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures as our evaluation of those impacts is ongoing. The estimates shown in the table 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;

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

• additional rules governing air pollutant transport;

• regulations 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 technology;

• 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 the construction of two scrubbers at the Newton energy center.

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

The decision to make pollution control equipment investments at AER depends on whether the expected future market price for power reflects the increased cost for environmental compliance. During early 2012, the observable market price for power for delivery in that year and in future years sharply declined below 2011 levels primarily because of declining natural gas prices, as well as the impact from the stay of the CSAPR. As a result of this sharp decline in the market price for power, as well as uncertain environmental regulations, Genco decelerated the construction of two scrubbers at its Newton energy center. The table above includes Genco's estimated costs of approximately $20 million annually, excluding capitalized interest, from 2013 through 2017 for the construction of the two Newton energy center scrubbers. Based on the MPS variance granted by the Illinois Pollution Control Board in September 2012, AER is currently scheduled to complete the Newton scrubbers by the end of 2019. See additional information below regarding the MPS variance granted by the Illinois Pollution Control Board.

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

Clean Air Act

Both federal and state laws require significant reductions in SO₂ and 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 required generating facilities in 28 states, including Missouri and Illinois, and the District of Columbia, to participate in cap-and-trade programs to reduce annual SO₂ emissions, 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. The CSAPR was to become effective on January 1, 2012, for SO₂ and annual NO_x reductions and on May 1, 2012, for ozone season NO_x reductions, with further reductions in 2014. 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 January 2013, the full Court of Appeals for the District of Columbia Circuit denied the EPA's request for rehearing. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the decision to vacate the CSAPR is overturned by the United States Supreme Court.

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

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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 that are not currently in place. 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, 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 comply with the MATS by April 2016.

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. Compliance with the finalized rule is required by 2020, or 2025 if an extension of time to achieve compliance is granted. Ameren is 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 standard for ozone. The EPA is required to revisit this standard 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 continue to assess the impacts of these new standards.

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 higher volumes of lower-sulfur-content coal than Ameren Missouri's energy centers have 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 within its coal-fired fleet, mercury control technology, and precipitator upgrades at multiple energy centers 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 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.

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 terms as, AER’s variance related to 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 the same relief as the existing AER variance. The Illinois Pollution Control Board has until late November 2013 to issue a decision. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of AER.

Under the MPS, AER is required to reduce mercury and NO_x emissions by 2015 and SO₂ emissions 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, Genco and AERG are installing equipment designed to reduce their emissions of mercury, NO_x, and SO₂. Genco and AERG have installed a total of three scrubbers at two energy centers. Two additional scrubbers are being constructed at Genco's 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.

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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 SO₂ emissions and created annual and ozone season NO_x allowances. Ameren expects to have adequate CAIR allowances for 2013 to avoid needing to make external purchases to comply with these programs.

Global Climate Change

State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change. Potential impacts from any climate change 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 climate change law 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, climate change regulations could cause the conversion of coal-fired power plants to natural gas, or the construction of new natural gas plants to replace coal-fired power plants. As a result, economywide 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 permits 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, if any, to control 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. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how state agencies apply the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in operations subject to the rule occur at our energy centers. In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld the Tailoring Rule.

Separately, in March 2012, the EPA issued the proposed Carbon Pollution Standard for New Power Plants. This proposed NSPS for greenhouse gas emissions would apply only to new fossil-fuel fired electric energy centers and therefore does not affect any of Ameren's existing energy centers. Ameren anticipates this proposed rule, if enacted, could make the construction of new coal-fired energy centers in the United States prohibitively expensive. A final rule is expected in 2013. Any federal climate change legislation that is enacted may preempt the EPA's regulation of greenhouse gas emissions, including the Tailoring Rule and the Carbon Pollution Standard for New Power Plants.

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. Moreover, to the extent Ameren Missouri requests recovery of these costs through rates, its regulators might delay or deny timely recovery of these costs. Excessive costs to comply with future legislation or regulations might force Ameren, Ameren Missouri and AER as well as other similarly situated electric power generators to close some coal-fired facilities earlier than planned, which could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren's results of operations, financial position, and liquidity.

Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change. 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. The case has been appealed to the appellate court.

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The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, their impact on our coal-fired energy centers and our customers' costs is unknown, but they could result in significant increases in our capital expenditures and operating costs. The 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.

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 should have 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. Genco believes its defenses to the allegations described in the Notice of Violation are meritorious. Ameren is unable to predict the outcome of this matter and whether the EPA will address this Notice of Violation administratively or through litigation.

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 alleges that in performing projects at its Rush Island coal-fired energy center, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the United States DistrictCourt granted, in part, Ameren Missouri's motion to dismiss various aspects of the EPA's penalty claims. The EPA's claims for injunctive relief, including to require the installation of pollution control equipment, remain. Litigation of this matter could take many years to resolve. Ameren Missouri believes its defenses to the allegations described in the complaint as well as the Notices of Violation are meritorious. Ameren Missouri 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. 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 percent 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 June 2013, with compliance expected within eight years thereafter. All coal-fired, nuclear, and combined cycle energy centers at 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. Ameren, Ameren Missouri and AER are currently evaluating the proposed rule, and their assessment of the proposed rule's impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule, if adopted, could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our energy centers.

In September 2009, the EPA announced its plan to revise the effluent guidelines applicable to steam electric generating units under the Clean Water Act. Effluent guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking. It has indicated that it expects to issue a proposed rule in April 2013 and to finalize the rule in May 2014. We are unable at this time to predict the impact of this development.

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

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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 all environmental liabilities associated with the Meredosia and Hutsonville energy centers will be assumed by Medina Valley. 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 16 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of New AER.

As of December 31, 2012, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois. These are in various stages of investigation, evaluation, remediation and closure. Based on current estimated plans, Ameren and 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 December 31, 2012, 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 from utility customers.

The following table presents, as of December 31, 2012, the estimated probable obligation to remediate these former MGP sites.

Estimate				Recorded Liability(a)
Low		High
$	257	$	339	$	257

(a) Recorded liability represents the estimated minimum probable obligations, as no other amount within the range provided a better estimate.

The scope and extent to which these sites are remediated has increased 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. While not currently mandated, Ameren Illinois may

be required to perform certain remediation activities associated with that landfill. As of December 31, 2012, Ameren Illinois estimated the obligation related to the cleanup at $0.5 million to $6 million. Ameren 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 December 31, 2012, Ameren 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 December 31, 2012, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren 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 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 December 31, 2012, 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 2013. Once the EPA has selected a remedy, if any, it would 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 the Sauget Area 2. As of December 31, 2012, Ameren Missouri estimated its obligation at $0.3 million to $10 million.

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Ameren 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 December 31, 2012, Ameren Missouri estimated the obligation related to the cleanup at $1.5 million to $2.3 million. Ameren recorded a liability of $1.5 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 ash pond facilities and 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. 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. We 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. We also 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.

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 December 31, 2012, Ameren had an insurance receivable balance of $68 million. Ameren'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 court ruled that the parties must first pursue alternative dispute resolution under the terms of their coverage agreement. 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 law voids the alternative dispute resolution provision of the insurance policy.

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, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In a November 2012 ruling, the United States District Court for the Eastern District of Missouri denied the insurer's motion to require arbitration. The insurer filed an appeal in the United States Court of Appeals for the Eighth Circuit.

Asbestos-related Litigation

Ameren has 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 as many as 272 parties named in some pending cases and as few as two in others. In the cases pending as of December 31, 2012, the average number of parties was 79.

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

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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 16 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren's divestiture of New AER.

The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of December 31, 2012:

Ameren	Ameren Missouri	Ameren Illinois	Total(a)
4	74	96	121

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

At December 31, 2012, Ameren had liabilities of $23 million recorded to represent its best estimate of its obligations related to asbestos claims.

Ameren Illinois has a tariff rider to recover the costs of 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 December 31, 2012, 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 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 only 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 2,100 local resident addresses primarily innewly annexed areas for the period 2005 through 2010. Ameren Illinois is challenging the city's position on this matter. Ameren Illinois believes its defenses to the notices of tax liability are meritorious and will defend itself vigorously.  As of December 31, 2012, Ameren Illinois did not believe it was probable that the city of O'Fallon would prevail and therefore have not recorded a charge to earnings for a loss contingency related to this matter.  Should Ameren Illinois ultimately be found liable for these prior-period municipal taxes, the amount is estimated between $2 million and $4 million, including interest and penalties. In addition, at the end of 2012, the city of O'Fallon and six other cities issued tax liability notices alleging that Ameren Illinois failed to collect prior-period taxes from certain local resident addresses. At this time, it is too early in Ameren

Illinois' review of the additional notices to reasonably estimate any likelihood of loss.

NOTE 16 - 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, which were distributed to Ameren in March 2013, (iii) the assets and liabilities associated with Genco’s Meredosia, Hutsonville, Elgin, Gibson City, and Grand Tower 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 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 $40 million at December 31, 2012. IPH will also acquire the estimated $15 million asset at December 31, 2012, relating to the overfunded status of one of EEI’s postretirement plans.

Ameren will retain Genco’s Meredosia and Hutsonville energy centers, which are no longer in operation and had an immaterial property and plant asset balance as of December 31, 2012. Ameren will also retain AROs associated with these energy centers, estimated at $26 million as of December 31, 2012. All other AROs associated with AER are expected to be assumed by either IPH 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

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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 December 31, 2012, 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. Ameren expects a third-party sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers will be completed by the end of 2013.

Completion of the New AER sale to IPH was subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC. On April 16, 2013, AER and Dynegy filed with FERC an application for approval of the divestiture of New AER and Genco’s sale of the Elgin, Gibson City, and Grand Tower natural 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. In addition, the FCC approval of the required license transfers 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 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 the same relief as the existing AER variance. The Illinois Pollution Control Board has until late November 2013 to issue a decision. See Note 15 - 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, subject to a 1 month extension to obtain FERC approval, 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.

Amended Put Option Agreement, Asset Purchase Agreement and Guaranty

See Note 14 - Related Party Transactions with New AER for additional information regarding the original put option agreement between Genco and AERG that was entered into on March 28, 2012.

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. 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 contains customary representations, warranties and covenants of Genco and Medina Valley. The consummation of the transactions contemplated by the asset purchase agreement is subject to certain conditions, including the receipt of FERC approval and other customary conditions.

A wholesale customer of Marketing Company has filed a lawsuit, in the United States District Court for the Central District of Illinois, against Ameren alleging that certain assets related to the amended put option agreement may not be sold without the customer’s consent, per the contract between the wholesale customer and Marketing Company. In addition, the lawsuit alleges that Genco and AERG failed to reflect a similar impairment of assets that was recorded by Ameren (parent) in the fourth quarter of 2012, which would have reduced the billings to the wholesale customer. Ameren 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

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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.

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 14 - Related Party Transactions with New AER for additional information regarding existing transactions between Ameren and New AER. Ameren does not expect to have significant continuing involvement with or material cash flows from the Elgin, Gibson City, and Grand Tower energy centers after their sale.

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 days period. The transitional services may be provided for 6 months after the closing and can be extended by IPH on a month-to-month basis for up to an additional 6 months.

See Note 15 - 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 contingencies.

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 consolidated statement of income (loss). 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.

The following table presents the components of discontinued operations in Ameren's consolidated statement of income (loss) for the year ended December 31, 2012, 2011 and 2010:

	Year ended
	2012				2011			2010
Operating revenues	$	1,047			$	1,278		$	1,369
Operating expenses	(3,478		)	(a)	(1,048		)	(1,578		)	(b)
Operating income (loss)	(2,431		)		230			(209		)
Other income (loss)	—				1			2
Interest charges	(56		)		(64		)	(83		)
Income (loss) before income taxes	(2,487		)		167			(290		)
Income tax (expense) benefit	989				(65		)	(51		)
Income (loss) from discontinued operations, net of taxes	$	(1,498	)		$	102		$	(341	)

(a) 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. In addition, includes a noncash pretax asset impairment charge of $1.95 billion to reduce the carrying values of all the AER coal and natural gas-fired energy centers, except the Joppa coal-fired energy center, to their estimated fair values, under held and used accounting guidance, as a result of the decision in December 2012 that Ameren intends to exit the Merchant Generation business.

(b) Includes a noncash pretax goodwill impairment charge of $420 million representing all the goodwill assigned to Ameren's Merchant Generation reporting unit as a result of proposed and pending environmental regulations which were expected to result in a significant increase in capital and operations and maintenance expenditures for the energy centers held by AER. Also, includes a $36 million noncash pretax asset impairment charge to reduce the carrying value of the Medina Valley energy center to its estimated fair value and a noncash pretax intangible asset impairment charge of $68 million to reduce existing SO₂ emission allowances to their estimated fair value.

Long-lived Asset Impairments

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Ameren's Merchant Generation segment has experienced decreasing earnings and cash flows from operating activities over the past few years, including in 2012, as margins have declined principally as a result of weaker power prices. In addition, environmental regulations have resulted in significant investment requirements over the same time frame. During this period, Ameren has increasingly focused on allocating its capital resources to those opportunities that it believes offer the most attractive risk-adjusted return potential, and specifically focused on growing earnings from its rate-regulated operations through investment under constructive regulatory frameworks. Ameren has sought to have its Merchant Generation segment fund its operations internally and not rely on financing from Ameren. In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously estimated useful lives of that business's long-lived assets. This determination resulted from Ameren's analysis of the current and projected future financial condition of its Merchant Generation segment, including the need to fund Genco debt maturities beginning in 2018, and its conclusion that this segment is no longer a core component of its future business strategy. In consideration of this determination, Ameren has begun planning to reduce, and ultimately eliminate, the Merchant Generation segment's reliance on Ameren's financial support and shared services support.

As a result of the December 2012 decision that Ameren intends to, and it is probable that it will, exit the Merchant Generation segment before the end of the Merchant Generation long-lived assets' previously estimated useful lives, Ameren determined that estimated undiscounted cash flows during the period in which it expects to continue to own certain energy centers would be insufficient to recover the carrying value of those energy centers. Accordingly, Ameren recorded a noncash pretax impairment charge of $1.95 billion in the fourth quarter of 2012 to reduce the carrying values of all of the Merchant Generation's coal and natural gas-fired energy centers, except the Joppa coal-fired energy center, to their estimated fair values. The estimated undiscounted cash flows of the Joppa coal-fired energy center exceeded its carrying value; therefore, the Joppa coal-fired energy center was unimpaired.

In early 2012, the observable market price for power for delivery in that year and in future years in the Midwest sharply declined below 2011 levels primarily because of declining natural gas prices and the impact of the stay of the CSAPR. As a result of this sharp decline in the market price of power and the related impact on electric margins, Genco decelerated the construction of two scrubbers at its Newton energy center in February 2012. 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. The carrying value of 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 that energy center to its estimated fair value during the first quarter of 2012.

During the third quarter of 2010, the aggregate impact of a sustained decline in market prices for electricity, industry market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted caused Ameren to evaluate if the carrying value of its Merchant Generation energy centers were recoverable. The Medina Valley energy center's carrying value exceeded its estimated undiscounted future cash flows. As a result, during 2010, Ameren recorded a noncash pretax asset impairment charges of $36 million to reduce the carrying value of the Medina Valley energy center to its estimated fair value. In 2012, Ameren sold the Medina Valley energy center.

Key assumptions used in the determination of estimated undiscounted cash flows of Ameren’s Merchant Generation segment’s long-lived assets tested for impairment included forward price projections for energy and fuel costs, the expected life or duration of ownership of the long-lived assets, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a discount rate and terminal year earnings multiples, were used to estimate the fair value of each energy center. These assumptions are subject to a high degree of judgment and complexity. The fair value estimate of these long-lived assets was based on a combination of the income approach, which considers discounted cash flows, and the market approach, which considers market multiples for similar assets within the electric generation industry. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements. Impairment within the Merchant Generation business segment was assessed at the energy center level.

Goodwill Impairment

We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Goodwill impairment testing is a two-step process. The first step involves a comparison of the estimated fair value of a reporting unit with its carrying amount. If the estimated fair value of the reporting unit exceeds the carrying value, goodwill of the reporting unit is considered unimpaired. If the carrying amount of the reporting unit exceeds its estimated fair value, a second step is performed to measure the amount of impairment, if any. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined by allocating the estimated fair value of the reporting unit to the estimated fair value of its existing assets and liabilities. The unallocated portion of the estimated fair value of the reporting unit is the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss equivalent to the difference is recorded as a reduction of goodwill and a charge to operating expense.

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During the third quarter of 2010, we concluded that events had occurred and circumstances had changed which, when considered in the aggregate, indicated that it was more likely than not that the fair value of Ameren’s Merchant Generation reporting unit was less than its carrying value. Such events and circumstances included the sustained decline in market prices for electricity, industry market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted. In July 2010, the EPA issued the proposed CSAPR. The proposed CSAPR, along with other pending regulations, was expected to result in a significant increase in capital and operations and maintenance expenditures for Ameren’s Merchant Generation energy centers.

Ameren’s Merchant Generation reporting unit failed step one of the 2010 interim impairment test, as the reporting unit’s carrying value exceeded its estimated fair value. Therefore, in order to measure the goodwill impairment in step two, we estimated the implied fair value of Ameren’s Merchant Generation goodwill. We determined that the implied fair value of goodwill was less than the carrying amount of goodwill, indicating that Ameren’s Merchant Generation goodwill was impaired. Based on the results of step two of the impairment test, Ameren recorded a noncash impairment charge of $420 million, which represented all of the goodwill assigned to Ameren’s Merchant Generation reporting unit.

The fair value estimate of Ameren’s Merchant Generation reporting unit was based on a combination of the income approach, which considers discounted future cash flows, and the market approach, which considers market comparables within the electric generation industry. Key assumptions in the determination of fair value included the use of an appropriate

discount rate, estimated five-year cash flows, and observable industry market multiples. We used our best estimates in making these evaluations. We considered various factors, including forward price projections for energy and fuel costs, environmental compliance costs, and operating costs. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements.

Intangible Assets Impairment

Prior to 2010, Ameren’s Merchant Generation business expected to use its SO₂ emission allowances for ongoing operations. In July 2010, the EPA issued the proposed CSAPR, which would have restricted the use of existing SO₂ emission allowances. As a result, Merchant Generation no longer expected all of its SO₂ emission allowances would be used in operations. Therefore, during 2010, Ameren recorded a $68 million pretax impairment charge to reduce the carrying value of Merchant Generation’s SO₂ emission allowances to their estimated fair value.

In July 2011, the EPA issued CSAPR, which created new allowances for SO₂ and NOx emissions and restricted the use of pre-existing SO₂ and NOx allowances to the acid rain program and to the NOx budget trading program, respectively. As a result, observable market prices for existing emission allowances declined materially. Consequently, Ameren recorded a noncash pretax impairment charge of $2 million in 2011 relating to Merchant Generation’s emission allowances.

The fair value of the SO₂ and NO_x emission allowances were based on observable and unobservable inputs, which were classified as Level 3 inputs for fair value measurements.

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The following table presents the carrying amounts of the components of assets and liabilities segregated on Ameren's consolidated balance sheets as discontinued operations at December 31, 2012 and 2011:

	December 31, 2012		December 31, 2011
Current assets of discontinued operations
Cash and cash equivalents	$	25	$	7
Accounts receivable and unbilled revenue	102		108
Materials and supplies	134		162
Mark-to-market derivative assets	102		65
Property and plant, net	748		3,279
Accumulated deferred income taxes, net	385		—
Other assets	104		97
Total current assets of discontinued operations	$	1,600	$	3,718
Current liabilities of discontinued operations
Accounts payable and other current obligations	$	133	$	134
Mark-to-market derivative liabilities	63		39
Long-term debt, net	824		824
Accumulated deferred income taxes, net	—		583
Asset retirement obligations	78		64
Pension and other postretirement benefits	40		92
Other liabilities	28		26
Total current liabilities of discontinued operations	$	1,166	$	1,762
Accumulated other comprehensive income (loss)(a)	$	19	$	(31	)
Noncontrolling interest(b)	$	8	$	7

(a) Accumulated other comprehensive income related to discontinued operations remains in “Accumulated other comprehensive loss” on Ameren’s December 31, 2012 and 2011, consolidated balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s consolidated balance sheet either before or at the closing of the New AER divestiture.

(b) The 20% ownership interest of EEI not owned by Ameren remains in “Noncontrolling interests” on Ameren’s December 31, 2012 and 2011, consolidated balance sheets. This noncontrolling interest will be removed from Ameren’s consolidated balance sheet at the closing of the New AER divestiture.

2013 Impairments

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Beginning on March 14, 2013, the New AER disposal group and the Elgin, Gibson City, and Grand Tower energy center disposal group both met the discontinued operations criteria. As a result, Ameren evaluated whether any impairment existed by comparing each disposal group’s carrying value to the estimated fair value of the disposal group, less cost to sell. Ameren recorded a cumulative pretax charge to earnings of $168 million for the six months ended June 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. 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 June 30, 2013. In December 2012, as discussed above, 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 energy centers, to their estimated fair values under the accounting guidance for held and used assets. An immaterial impairment was recorded by Ameren for the three gas-fired energy centers during the six months ended June 30, 2013, as 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 adjusted accumulated deferred income taxes on its consolidated balance sheet to reflect the excess of tax basis over financial reporting basis of its stock investment in AER, during 2013, when it became apparent that the temporary difference would reverse. Ameren recorded a discontinued operations deferred tax expense of $97 million, which was partially offset by the expected tax benefits of $69 million related to the 2013 impairment charge, during the six months ended June 30, 2013. 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 IRS 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 June 30, 2013.

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

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 December 31, 2012:

	Required Ratio	Actual Ratio
Interest coverage ratio- restricted payment (a)	≥1.75	2.6
Interest coverage ratio- additional indebtedness (b)	≥2.50	2.6
Debt-to-capital ratio- additional indebtedness (b)	≤60%	44	%

(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.

Genco's indenture includes restrictions that 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 December 31, 2012, of Genco's operating results and cash flows in 2013 and 2014, we did not believe that

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Genco would achieve the minimum interest coverage ratio necessary to pay dividends on its common stock for each of the subsequent four six-month periods ending June 30, 2013, December 31, 2013, June 30, 2014, or December 31, 2014. As a result, Genco was restricted from paying dividends on its common stock as of December 31, 2012, and we expect Genco will be unable to pay dividends on its common stock in 2013, 2014, and 2015.

Illinois Sales and Use Tax Exemptions and Credits

In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear an appeal of the case, and the decision became final. During the second quarter of 2010, Genco, including EEI, and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The primary basis for those claims is that the determination in the Exelon casethat electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. In November 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois' position that EEI did not qualify for the manufacturing exemption it used during 2010. As of December 31, 2012, Ameren did not believe that it was probable that the state of Illinois will prevail and therefore had not recorded a charge to earnings for the loss contingency. During second quarter of 2013, Ameren and the Department of Revenue resolved the tax liabilities for all open periods related to this issue with a payment of $7 million by Genco, including EEI, and AERG to the Illinois Department of Revenue.

NOTE 17 - IMPAIRMENT AND OTHER CHARGES

The following table summarizes the pretax charges recorded in the consolidated statement of income (loss) as “Impairment and other charges” for the years ended December 31, 2012, 2011, and 2010:

	2012		2011		2010
Long-Lived Assets and Related Charges	$	—	$	123	$	64

The impairment charges did not result in a violation of any Ameren or Ameren subsidiary debt covenants or counterparty agreements. Each of the charges is discussed below.

The Ameren Companies evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the

assets. If the carrying value exceeds the undiscounted cash flows, the Ameren Companies recognize an impairment charge equal to the amount of the carrying value of the assets that exceeds its estimated fair value.

In December 2011, Genco ceased operations of its Meredosia and Hutsonville energy centers. As a result, Ameren recorded a noncash pretax asset impairment charge of $26 million to reduce the carrying value of the Meredosia and Hutsonville energy centers to their estimated fair values, a $4 million impairment of materials and supplies, and $4 million for severance costs. See Note 1 - Summary of Significant Accounting Policies for further information regarding severance costs.

During 2011, the MoPSC issued an electric rate order that disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of the amount recovered from property insurance. Consequently, Ameren recorded a pretax charge to earnings of $89 million.

During the third quarter of 2010, the aggregate impact of a sustained decline in market prices for electricity, industry transaction market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted caused Ameren to evaluate if the carrying value of its Merchant Generation energy centers were recoverable. The Meredosia energy center's carrying value exceeded its estimated undiscounted future cash flows. As a result, during 2010, Ameren recorded a noncash pretax asset impairment charge of $64 million to reduce the carrying value of the Meredosia energy center to its estimated fair value.

Key assumptions used in the determination of estimated undiscounted cash flows of Ameren’s long-lived assets tested for impairment included forward price projections for energy and fuel costs, the expected life or duration of ownership of the long-lived assets, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a discount rate and terminal year earnings multiples, were used to estimate the fair value of each energy center. These assumptions are subject to a high degree of judgment and complexity. The fair value estimate of these long-lived assets was based on a combination of the income approach, which considers discounted cash flows, and the market approach, which considers market multiples for similar assets within the electric generation industry. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements. Impairment within the Merchant Generation business was assessed at the energy center level. Ameren does not expect to incur material future cash expenditures as a result of these impairments.

NOTE 18 - SEGMENT INFORMATION

Ameren has three reportable segments: Ameren Missouri, Ameren Illinois, and Merchant Generation. The Ameren Missouri segment includes all the operations of Ameren Missouri’s business as described in Note 1 - Summary of Significant Accounting Policies. The Ameren

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Illinois segment 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 consisted primarily of the operations or activities of AER, including Genco, EEI, AERG, and Marketing Company. Ameren is divesting its Merchant Generation segment and therefore has excluded that segment's information below. See Note 16 - 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 16 - Divestiture Transactions and Discontinued Operations for information regarding the assets and liabilities to be retained by Ameren after the divestitures.

The following table presents information about the reported revenues and specified items reflected in net income attributable to Ameren Corporation from continuing operations for the years ended December 31, 2012, 2011, and 2010, and total assets as of December 31, 2012, 2011, and 2010.

Ameren

	Ameren Missouri		Ameren Illinois		Other				Intersegment Eliminations			Consolidated
2012
External revenues	$	3,252	$	2,524	$	5			$	—		$	5,781
Intersegment revenues	20		1		3				(24		)	—
Depreciation and amortization	440		221		6				—			667
Interest and dividend income	32		—		—				—			32
Interest charges	223		129		39				—			391
Income taxes (benefit)	252		94		(37		)		—			309
Net income (loss) attributable to Ameren Corporation from continuing operations	416		141		(39		)		—			518
Capital expenditures	595		442		26				—			1,063
Total assets	13,043		7,282		1,228				(934		)	20,619		(a)
2011
External revenues	$	3,360	$	2,784	$	83			$	—		$	6,227
Intersegment revenues	23		3		3				(29		)	—
Depreciation and amortization	408		215		23				—			646
Interest and dividend income	30		1		—				—			31
Interest charges	209		136		42				—			387
Income taxes (benefit)	161		127		(43		)		—			245
Net income (loss) attributable to Ameren Corporation from continuing operations	287		193		(62		)		—			418
Capital expenditures	550		351		(20		)	(b)	—			881
Total assets	12,757		7,213		1,211				(1,176		)	20,005		(a)
2010
External revenues	$	3,180	$	3,012	$	77			$	—		$	6,269
Intersegment revenues	17		2		—				(19		)	—
Depreciation and amortization	382		210		35				—			627
Interest and dividend income	31		1		—				—			32
Interest charges	213		143		59				—			415
Income taxes (benefit)	199		137		(62		)		—			274
Net income (loss) attributable to Ameren Corporation from continuing operations	364		208		(89		)		—			483
Capital expenditures	624		281		36				—			941
Total assets	12,504		7,406		1,354				(1,541		)	19,723		(a)

(a) Excludes "Current assets for discontinued operations." See Note 16 - Divestiture Transactions and Discontinued Operations for additional information.

(b) Includes the elimination of intercompany transfers.

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SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)

	2012										2011
Quarter ended (a)	March 31			June 30		September 30		December 31			March 31		June 30		September 30		December 31
Operating Revenues	$	1,412		$	1,402	$	1,709	$	1,258		$	1,597	$	1,458	$	1,876	$	1,296
Operating Income (b)	158			344		578		111			156		270		494		91
Net Income (Loss)	(403		)	210		374		(1,155		)	74		139		287		26
Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations	$	37		$	161	$	305	$	15		$	38	$	116	$	265	$	(1	)
Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations (c)	(440		)	50		69		(1,171		)	33		22		20		26
Net Income (Loss) Attributable to Ameren Corporation	$	(403	)	$	211	$	374	$	(1,156	)	$	71	$	138	$	285	$	25
Earnings (Loss) per Common Share - Basic and Diluted - Continuing Operations	$	0.15		$	0.66	$	1.26	$	0.06		$	0.16	$	0.48	$	1.10	$	(0.01	)
Earnings (Loss) per Common Share - Basic and Diluted - Discontinued Operations	(1.81		)	0.21		0.28		(4.82		)	0.13		0.09		0.08		0.11
Earnings (Loss) per Common Share - Basic and Diluted	$	(1.66	)	$	0.87	$	1.54	$	(4.76	)	$	0.29	$	0.57	$	1.18	$	0.10

(a) The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is due to the effects of rounding and changes in the number of weighted-average shares outstanding each period.

(b) Includes pretax "Impairment and other charges" of $123 million recorded to continuing operations during the year ended December 31, 2011. See Note 17 - Impairment and Other Charges for additional information.

(c) Includes a pretax asset impairment charge of $2.578 billion recorded to discontinued operations during the year ended December 31, 2012. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information.

During preparation of the 2012 annual statement of cash flows, errors were identified in Ameren's 2012 interim statement of cash flows. The errors, which were $14 million, $26 million, and $49 million through the year-to-date first, second, and third quarters of 2012, respectively, are not considered material. The errors related to the classification of certain activity from the nuclear decommissioning trust fund and increased operating cash flows and reduced investing cash flows for each of these year-to-date periods. The 2012 interim statement of cash flows will be revised to correct for these errors in the Ameren 2013 Form 10-Q filings.

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