8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of report (Date of earliest event reported):

October 17, 2013

AMEREN CORPORATION

(Exact name of registrant as specified in its charter)

Missouri	1-14756	43-1723446
(State of other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification Number)

1901 Chouteau Avenue, St. Louis, Missouri 63103

(Address of principal executive offices and Zip Code)

Registrant's telephone number, including area code: (314) 621-3222

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ] Pre‑commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[ ] Pre‑commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

ITEM 8.01Other Events.

As previously reported, on March 14, 2013, Ameren Corporation (“Ameren”) entered into a transaction agreement to divest its Merchant Generation business to Illinois Power Holdings, LLC (“IPH”), an indirect wholly owned subsidiary of Dynegy, Inc. Under the terms of the transaction agreement with IPH, Ameren Energy Resources Company, LLC ("AER") will effect a reorganization that will, among other things, transfer substantially all of the assets and liabilities of AER to the newly created limited liability company that is a direct wholly owned subsidiary of AER ("New AER"). Immediately prior to Ameren's entry into the transaction agreement with IPH, Ameren Energy Generating Company (“Genco”) exercised its option under the amended put option agreement with AmerenEnergy Medina Valley Cogen LLC (“Medina Valley”) to sell Genco's Elgin, Gibson City, and Grand Tower gas‑fired energy centers (the “Put Option Assets”) to Medina Valley. Ameren expects a third-party sale of the Put Option Assets will be completed by the end of 2013. As a result of Ameren's entry into the transaction agreement and its plan to sell the Put Option Assets, Ameren segregated New AER's and the Put Option Assets' operating results, assets, and liabilities and presented them separately as discontinued operations for all periods presented beginning with Ameren's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, filed with the U.S. Securities and Exchange Commission (“SEC”) on May 10, 2013.

Ameren is filing this Current Report on Form 8-K to recast Ameren's consolidated financial statements and certain other financial information included in Ameren's Annual Report on Form 10-K for the year ended December 31, 2012 (“Form 10-K”), filed with the SEC on March 1, 2013. The relevant financial information in the Form 10-K is being recast solely to reflect the impact of the discontinued operations presentation for New AER and the Put Option Assets as of the dates and for the periods covered by such consolidated financial statements. All other information in the Form 10-K remains unchanged.

Ameren has recast the following portions of the Form 10-K to reflect the discontinued operations presentation described above:

Item 6.     Selected Financial Data

Item 7.     Management's Discussion and Analysis of Financial Condition and Results of Operations

Item 7A.     Quantitative and Qualitative Disclosures about Market Risk

Item 8.     Financial Statements and Supplementary Data

Schedule I.     Condensed Financial Information of Parent

Schedule II.     Valuation and Qualifying Accounts

Exhibit 12.1     Computation of Ratio of Earnings to Fixed Charges

The recast portions of the Form 10-K described above are attached as Exhibits 99.1, 99.2, 99.3, 99.4, 99.5, 99.6, and 12.1 hereto, respectively, and incorporated herein by reference.

Except as described above, the information contained herein does not modify or update the disclosures contained in the Form 10-K in any way, nor does it reflect any information or events, subsequent to the date of the Form 10-K. Without limitation to the foregoing, this information does not purport to update the MD&A for any information, uncertainties, risks, events or trends occurring or known to management. Therefore, the information contained herein should be read in conjunction with the Form 10-K and Ameren's other filings with the SEC under the Securities Exchange Act of 1934 subsequent to the filing of the Form 10-K, including its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013, as filed with the SEC on May 10, 2013 and August 9, 2013, respectively. The information contained herein is not an amendment to, or a restatement of, the Form 10-K.

As filed with the SEC on March 1, 2013, the Form 10-K was a combined filing by Ameren and two of its registrant subsidiaries, Union Electric Company ("Ameren Missouri"), and Ameren Illinois Company ("Ameren Illinois"). The recast of Ameren's consolidated financial statements and certain other financial information to reflect New AER and the Put Option Assets as discontinued operations did not impact Ameren Missouri's or Ameren Illinois' financial statements as previously filed; accordingly, Ameren Missouri's and Ameren Illinois' financial statements and related disclosures have not been recast and are not being modified or updated by the information contained in this Current Report on Form 8-K.

The words “our,” “we” or “us” are used in Exhibits 12.1, 99.1, 99.2, 99.3, 99.4, 99.5, and 99.6 hereto with respect to certain information that relates to Ameren. When appropriate, subsidiaries of Ameren Corporation are named specifically as their various business activities are discussed. Refer to the “Glossary of Terms and Abbreviations” in Ameren's Form 10-K for the year ended December 31, 2012, and as updated by the “Glossary of Terms and Abbreviations” in Ameren's Form 10-Q for the quarter ended June 30, 2013, for a complete listing of glossary terms and abbreviations.

ITEM 9.01Financial Statements; Exhibits.

(d) Exhibits

Exhibit Number: Title:

12.1 Computation of Ratio of Earnings to Fixed Charges

23.1 Consent of PricewaterhouseCoopers LLP

99.1 Item 6. Selected Financial Data

99.2 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

99.3 Item 7A. Quantitative and Qualitative Disclosures about Market Risk

99.4 Item 8. Financial Statements and Supplementary Data

99.5 Schedule I. Condensed Financial Information of Parent

99.6 Schedule II. Valuation and Qualifying Accounts

101.INS XBRL Instance Document

101.SCH XBRL Taxonomy Extension Schema Document

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB XBRL Taxonomy Extension Label Linkbase Document

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF XBRL Taxonomy Extension Definition Document

Forward-looking Statements

Statements in this report, including the exhibits hereto, not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. As noted above, the information from the Form 10-K (including any forward-looking statements) reflected in this report has not been modified or updated, nor does it reflect any information or events subsequent to the date of the Form 10-K, other than to reflect the impact of the discontinued operations presentation for New AER and the Put Option Assets. Although such forward-looking statements have been made in good faith and based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed under Risk Factors in the Form 10-K and in Ameren's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, as well as those discussed elsewhere in this report, including the exhibits hereto, and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:.

• completion of our divestiture of New AER and the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers;

• regulatory approvals, including from the Federal Energy Regulatory Commission (“FERC”), the Federal Communications Commission and the Illinois Pollution Control Board relating to, and the satisfaction or waiver of the conditions to, the divestiture of New AER and regulatory approvals from FERC with respect to both the transfer to Medina Valley and ultimate sale to a third-party of the Elgin, Gibson City, and Grand Tower gas-fired energy centers;

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

• regulatory, judicial, or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the outcome of Ameren Illinois' natural gas delivery service rate case filed in 2013; the court appeals of Ameren Missouri's and Ameren Illinois' electric rate orders issued in 2012; Ameren Missouri's current fuel adjustment clause prudence review by the Missouri Public Service Commission; Ameren Missouri's request with the MoPSC for an accounting authority order relating to the deferral of certain fixed costs; Ameren Illinois' request for rehearing of FERC's July 2012 and June 2013 orders regarding the alleged inclusion of acquisition premiums in Ameren Illinois transmission rates; and future regulatory, judicial, or legislative actions that seek to change regulatory recovery mechanisms;

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

• the decision of when Ameren Illinois would begin to participate in the regulatory framework provided by the state of Illinois' recently enacted Natural Gas Consumer, Safety and Reliability Act, which allows for the use of a rider to recover costs of certain infrastructure investments made between rate cases;

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

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

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

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

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

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

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

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

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

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

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

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

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

• the impact of weather conditions and other natural phenomena on us and our customers, including the impacts of droughts, which may cause lower river levels and could limit our energy centers' ability to generate power;

• the impact of system outages;

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

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

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

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

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

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

• the impact of current environmental regulations on utilities and power generating companies and new, more stringent or changing requirements, including those related to greenhouse gases, other emissions and discharges, cooling water intake structures, coal combustion residuals, and energy efficiency, that are enacted over time and that could limit or terminate the operation of certain of our energy centers, increase our costs, result in an impairment of our assets, result in sales of our assets, reduce our customers' demand for electricity or natural gas, or otherwise have a negative financial effect;

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

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

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

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

• legal and administrative proceedings; and

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

Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

AMEREN CORPORATION

(Registrant)

    Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer

Date: October 17, 2013

Exhibit Index

Exhibit Number: Title:

12.1 Computation of Ratio of Earnings to Fixed Charges

23.1 Consent of PricewaterhouseCoopers LLP

99.1 Item 6. Selected Financial Data

99.2 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

99.3 Item 7A. Quantitative and Qualitative Disclosures about Market Risk

99.4 Item 8. Financial Statements and Supplementary Data

99.5 Schedule I. Condensed Financial Information of Parent

99.6 Schedule II. Valuation and Qualifying Accounts

101.INS XBRL Instance Document

101.SCH XBRL Taxonomy Extension Schema Document

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB XBRL Taxonomy Extension Label Linkbase Document

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF XBRL Taxonomy Extension Definition Document

EX-12.1

EXHIBIT 12.1

Ameren Corporation

Computation of Ratio of Earnings to Fixed Charges

(Thousands of Dollars, Except Ratios)

	Year Ended December 31,
	2008		2009		2010		(a)	2011		(b)	2012
Earnings available for fixed charges, as defined:
Net income from continuing operations attributable to Ameren Corporation	$	181,189	$	367,827	$	483,414		$	417,596		$	517,398
Tax expense (benefit) based on income	128,160		154,369		273,927			245,191			308,590
Fixed charges excluding preferred stock dividends tax adjustment (c)	393,395		465,523		458,490			427,593			422,264
Earnings available for fixed charges, as defined	$	702,744	$	987,719	$	1,215,831		$	1,090,380		$	1,248,252
Fixed charges, as defined:
Interest expense on short-term and long-term debt  (c)	$	359,414	$	427,663	$	426,666		$	397,618		$	389,496
Estimated interest cost within rental expense	5,331		7,211		7,476			7,193			7,024
Amortization of net debt premium, discount, and expenses	18,293		20,775		16,070			16,754			19,301
Subsidiary preferred stock dividends	10,357		9,874		8,278			6,028			6,443
Adjust preferred stock dividends to pretax basis	6,989		6,279		4,942			3,859			4,032
Total fixed charges, as defined	$	400,384	$	471,802	$	463,432		$	431,452		$	426,296
Consolidated ratio of earnings to fixed charges	1.76		2.09		2.62			2.53			2.93

(a) In 2010, Ameren Corporation recorded an impairment charge of $64 million related to the Meredosia energy center. See Note 17 - Impairment and Other Charges under Exhibit 99.4, Item 8 of this current report on Form 8-K for additional information.

(b) In 2011, Ameren Corporation recorded a charge to earnings of $123 million related to an Ameren Missouri loss on regulatory disallowance and charges related to the closure of the Meredosia and Hutsonville energy centers. See Note 17 - Impairment and Other Charges under Exhibit 99.4, Item 8 of this current report on Form 8-K for additional information.

(c) Includes interest expense related to uncertain tax positions.

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-175151 and 333-182258) and the Registration Statements on Form S-8 (Nos. 333−50793, 333−133998, and 333−157655)of our reportdated March 1, 2013, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of discontinued operations described in Note 16, which is as of October 17, 2013, relating to the financial statements, financial statement schedules and the effectiveness of internal control over financial reporting, which appears in this Form 8-K.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

October 17, 2013

EX-99.1

EXHIBIT 99.1

ITEM 6.SELECTED FINANCIAL DATA                            

For the years ended December 31, (In millions, except per share amounts)	2012			2011		2010		2009		2008
Operating revenues	$	5,781		$	6,227	$	6,269	$	5,904	$	6,512
Operating income	1,191			1,011		1,125		911		685
Income from continuing operations	524			424		492		382		248
Net income (loss) attributable to Ameren Corporation	(974		)	519		139		612		605
Common stock dividends	382			375		368		338		534
Continuing operations earnings per share - basic and diluted	2.13			1.73		2.02		1.67		0.86
Common stock dividends per share	1.60			1.555		1.54		1.54		2.54
As of December 31:
Total assets(a)	$	22,219		$	23,723	$	23,511	$	23,702	$	22,671
Long-term debt, excluding current maturities(b)	5,802			5,853		6,030		6,287		5,523
Total Ameren Corporation stockholders’ equity	6,616			7,919		7,730		7,856		6,963

(a) Includes total assets from discontinued operations of $1,600 million, $3,718 million, $3,788 million, $4,484 million, and $4,521 million at December 31, 2012, 2011, 2010, 2009 and 2008, respectively.

(b) Excludes long-term debt from discontinued operations.

EX-99.2

EXHIBIT 99.2

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

Ameren Executive Summary

Operations

While working to exit the Merchant Generation business as discussed below, Ameren remains focused on its rate-regulated utilities, including growing investments in jurisdictions with constructive regulatory frameworks. Ameren continues to seek modern, constructive regulatory frameworks, which provide timely cash flows and a reasonable opportunity to earn fair returns on investments that are in the best long-term interest of Ameren's customers. These frameworks support Ameren's rate-regulated businesses' ability to obtain cash on a timelier basis, to reinvest in energy infrastructure and also attract capital on terms that facilitate timely investments to modernize their aging infrastructure.

In December 2012, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $260 million. These new rates became effective on January 2, 2013. The MoPSC's December 2012 electric rate order improved Ameren Missouri's regulatory framework for energy efficiency programs as well as authorized the implementation of a new storm restoration cost tracking mechanism.

In 2012, Ameren Illinois elected to participate in the IEIMA's performance-based formula ratemaking framework. The IEIMA was designed to promote investment in electric grid modernization and create jobs through the establishment of formula ratemaking for electric delivery service. Ameren Illinois believes the ICC has incorrectly implemented the IEIMA in both of its 2012 electric delivery service rate orders. As a result, Ameren Illinois has appealed both 2012 electric delivery service rate orders to the Appellate Court of the Fourth District of Illinois and is also seeking a legislative solution to address the ICC's implementation of the IEIMA. Additionally, in January 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service by $50 million. This request was based on a 2014 future test year.

Ameren continues to proceed with its plans to increase its investment in FERC-regulated electric transmission. In 2013, for both Ameren Illinois and ATXI, transmission rates will be updated annually based on a forward-looking calculation with a revenue requirement reconciliation. Ameren expects to invest a total of approximately $2.2 billion in FERC-regulated transmission projects over the next five years. The Ameren Illinois portion of that total, approximately $1 billion, is for projects focused on local load growth and reliability needs. ATXI, through its construction of three MISO-approved regional multi-value electric transmission projects, expects to invest approximately $1.2 billion over the next five years. In November 2012, ATXI filed a request with the ICC for a certificate of public convenience and necessity for the

Illinois Rivers project. Once ATXI receives the certificate of public convenience and necessity, it can begin to acquire right of way for the Illinois Rivers project. A full range of construction activities for the Illinois Rivers project is expected to begin in 2014.

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 segment's long-lived assets, which resulted in a $1.95 billion pretax impairment charge. On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Pursuant to the transaction agreement, Ameren is required to operate New AER, including Genco, 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. 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. 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 under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information regarding these divestitures.

Earnings

Ameren reported a net loss of $974 million, or $4.01 per share, for 2012 compared with net income of $519 million, or $2.15 per share, in 2011. Net income attributable to Ameren Corporation from continuing operations was $518 million, or $2.13 per share, for 2012 and $418 million, or $1.73 per share, for 2011. Ameren's earnings from continuing operations increased in 2012, compared with 2011, in part, because of increased Ameren Missouri earnings due primarily to the full year effect of the 2011 electric rate increase as well as lower operations and maintenance expense reflecting the absence of a refueling outage at the Callaway energy center in 2012, decreased labor costs primarily due to staff reductions resulting from the 2011 voluntary separation plan, and reduced major storm-related costs. Ameren Missouri's 2012 earnings, compared to 2011 earnings, also benefited from a favorable 2012 FERC order related to a disputed power purchase agreement that expired in 2009 and the absence of a 2011 charge to earnings related to the FAC. These positive Ameren Missouri factors were partially offset by higher depreciation expense and lower electric sales volumes due to warmer 2012 winter temperatures. The earnings increase in the Ameren Missouri segment was partially offset by a decline in Ameren Illinois' earnings primarily due to the impacts of implementing the IEIMA's formula ratemaking in 2012, including a

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lower allowed return on equity and required nonrecoverable contributions, as well as lower natural gas sales volumes as a result of warmer 2012 winter temperatures. Summer weather was much warmer than normal in 2012, but similar to 2011. The net loss attributable to Ameren Corporation from discontinued operations was $1,492 million, or $6.14 per share, for 2012 compared with net income of $101 million, or $0.42 per share, for 2011. The main factors contributing to the net loss in 2012, compared with net income in 2011, were the 2012 impairments of Merchant Generation's long-lived assets resulting from the first quarter impairment of the Duck Creek energy center and Ameren's determination in December 2012 that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously useful lives of that business segment's long-lived assets, coupled with the sharp decline in the market price for power in the first quarter of 2012. The decline in Merchant Generation earnings also reflected lower power prices and higher fuel costs.

Liquidity

Cash flows from operations associated with continuing operations of $1.4 billion were used to pay dividends to common stockholders of $382 million and to fund capital expenditures associated with continuing operations of $1.1 billion. At December 31, 2012, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under existing credit agreements, of approximately $2.3 billion.

Capital Spending

From 2013 through 2017, Ameren's cumulative capital spending associated with continuing operations is projected to range between $7.1 billion and $9.2 billion. The spending includes a total of approximately $1.2 billion at ATXI to invest in its electric transmission assets as discussed above.

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. See Note 1 - Summary of Significant Accounting Policies under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for a detailed description of our principal subsidiaries.

• Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business, and a rate-regulated natural gas transmission and distribution

business in Missouri.

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

• AER consists of non-rate-regulated operations, including Genco, AERG, 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 under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information regarding that presentation.

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 was 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 under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information.

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 under Exhibit 99.4, Item 8, of this Current Report on Form 8-K 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. Therefore, Ameren has segregated New AER's and the Elgin, Gibson City, and Grand

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Tower gas-fired energy centers' operating results, assets, and liabilities and presented them separately as discontinued operations for all periods presented in this Current Report on Form 8-K. Unless otherwise noted, the following sections of Management's Discussion and Analysis of Financial Condition and Results of Operations have been revised to exclude discontinued operations for all periods presented. All other information in this Current Report on Form 8-K 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 under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information regarding the divestiture and discontinued operations 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 transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

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

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. The vast majority of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the prices we charge for our services. We principally use coal, nuclear fuel, natural gas, methane gas, and oil for fuel in our operations. The prices for these commodities can fluctuate significantly because of the global economic and political environment, weather, supply and demand, and many other factors. We have natural gas cost recovery mechanisms for our Illinois and Missouri natural gas delivery service businesses, a purchased power cost recovery mechanism for our Illinois electric delivery service business, and a FAC for our Missouri electric utility business. Ameren Illinois' electric delivery service utility business, pursuant to the IEIMA, conducts an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for that year, with recoveries from or refunds to customers in a subsequent year. Included in

Ameren Illinois' revenue requirement reconciliation is a formula for the return on equity, which is equal to the average of the monthly yields of 30-year United States treasury bonds plus 590 basis points for 2012 and 580 basis points thereafter. Therefore, Ameren Illinois' annual return on equity will be directly correlated to yields on United States treasury bonds. Fluctuations in interest rates and conditions in the capital and credit markets also affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our energy centers and transmission and distribution systems and the level of purchased power costs, operations and maintenance costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.

Earnings Summary

Net loss attributable to Ameren Corporation was $974 million, or a loss of $4.01 per share, for 2012. Net income attributable to Ameren Corporation from continuing operations was $518 million, or $2.13 per share, for 2012. Net income attributable to Ameren Corporation was $519 million, or $2.15 per share, for 2011, and $139 million, or $0.58 per share, for 2010. Net income attributable to Ameren Corporation from continuing operations was $418 million, or $1.73 per share, for 2011, and $483 million, or $2.02 per share, for 2010.

2012 versus 2011

Net income attributable to Ameren Corporation from continuing operations in 2012 increased $100 million, or $0.40 per share, from 2011. Net income attributable to Ameren Corporation increased in the Ameren Missouri segment by $129 million, which was partially offset by a decrease in the Ameren Illinois segment of $52 million.

Compared with 2011 earnings per share from continuing operations, 2012 earnings from continuing operations were favorably affected by:

• the absence in 2012 of charges recorded in 2011 for the MoPSC's July 2011 disallowance of costs of enhancements relating to the rebuilding of Ameren Missouri's Taum Sauk energy center in excess of amounts recovered from property insurance and for the closure of the Meredosia and Hutsonville energy centers (32 cents per share);

• higher utility rates at Ameren Missouri and Ameren Illinois. Ameren Missouri's electric rates increased pursuant to an order issued by the MoPSC, which became effective in July 2011. The favorable impact of the Ameren Missouri rate increase on earnings was reduced by the increased regulatory asset amortization directed by the rate order. Ameren Illinois' natural gas rates increased pursuant to an order issued by the ICC, which became effective in mid-January 2012 (22 cents per share);

• the absence in 2012 of a Callaway energy center refueling and maintenance outage (11 cents per share);

• the impact of fewer major storms on operations and

3

maintenance expenses (9 cents per share);

• a reduction in Ameren Missouri's purchased power expense and an increase in interest income, each as a result of a FERC-ordered refund received in 2012 from Entergy for a power purchase agreement that expired in 2009 (7 cents per share);

• the absence in 2012 of a 2011 charge associated with voluntary separation offers to eligible Ameren Missouri and Ameren Services employees (7 cents per share);

• the absence in 2012 of a reduction in Ameren Missouri's revenues as a result of the MoPSC's April 2011 FAC prudence review order covering the period from March 1, 2009, to September 30, 2009, which resulted in Ameren Missouri recording an obligation to refund to its electric customers the earnings associated with certain previously recognized sales (5 cents per share); and

• reduction in operations and maintenance expenses at Ameren Missouri energy centers due to fewer outages and a reduction in employees (2 cents per share).

Compared with 2011 earnings per share from continuing operations, 2012 earnings from continuing operations were unfavorably affected by:

• a reduction in Ameren Illinois' electric earnings primarily caused by a lower allowed return on equity under electric delivery service formula ratemaking and required donations pursuant to the IEIMA (17 cents per share);

• an increase in Ameren Missouri depreciation and amortization expense caused primarily by the installation of scrubbers at the Sioux energy center (8 cents per share);

• reduced electric and natural gas demand as a result of warmer 2012 winter temperatures (estimated at 7 cents per share);

• the absence of margin from the Meredosia and Hutsonville energy centers due to their closure in 2011, partially offset by a reduction in depreciation expense related to these energy centers, including a 2011 change in estimate related to asset retirement obligations (7 cents per share); and

• reduced rate-regulated retail sales volumes, excluding the effects of abnormal weather, as sales volumes declined due to continued economic pressure, energy efficiency measures, and customer conservation efforts, among other items (2 cents per share).

The cents per share information presented above is based on average shares outstanding in 2011.

2011 versus 2010

Net income attributable to Ameren Corporation from continuing operations decreased $65 million, or $0.29 per share, in 2011 compared with 2010. Net income attributable to Ameren Corporation decreased in the Ameren Missouri segment and Ameren Illinois segment by $77 million and $15 million, respectively, in 2011 compared with 2010.

Compared with 2010 earnings per share from continuing operations, 2011 earnings from continuing operations were

unfavorably affected by:

• a charge to earnings related to the MoPSC’s July 2011 disallowance of costs of enhancements relating to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance (23 cents per share);

• reduced rate-regulated retail sales volumes, excluding the effects of abnormal weather, as sales volumes declined due to continued economic pressure, energy efficiency measures, and customer conservation efforts as well as lower wholesale sales at Ameren Missouri due to a reduction in customers and the expiration of favorably priced contracts, among other items (15 cents per share);

• the impact of weather conditions on electric and natural gas demand (estimated at 10 cents per share);

• increased operations and maintenance expenses as a result of major storms in 2011 (9 cents per share);

• a reduction in allowance for equity funds used during construction reflecting the 2010 completion of two scrubbers at Ameren Missouri’s Sioux energy center (8 cents per share);

• reduced income tax benefit driven by reduced impairment charges relating to the Meredosia and Hutsonville energy centers, depreciation and interest charges (8 cents per share);

• increased operations and maintenance expenses associated with voluntary separation offers to eligible Ameren Missouri and Ameren Services employees during 2011 (7 cents per share);

• a reduction in revenues resulting from the MoPSC’s April 2011 order with respect to its FAC review for the period from March 1, 2009, to September 30, 2009, as discussed above. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information (5 cents per share); and

• an increase in depreciation and amortization expense caused primarily by the installation of scrubbers at Ameren Missouri’s Sioux energy center as well as other capital additions (4 cents per share).

Compared with 2010 earnings per share from continuing operations, 2011 earnings from continuing operations were favorably affected by:

• higher Ameren Missouri electric rates pursuant to orders issued by the MoPSC, which became effective in June 2010 and in July 2011, as well as higher Ameren Missouri natural gas rates pursuant to a MoPSC order, which became effective in late February 2011. The impact of the Ameren Missouri electric rate increases on earnings was reduced by the adoption of life span depreciation methodology, recognition in 2010 of regulatory assets for previously expensed costs in the prior-year period, and increased regulatory asset amortization as directed by the rate orders (17 cents per share). These amounts exclude the unfavorable impact of the charge to earnings related to the MoPSC’s disallowance of Taum Sauk rebuilding costs discussed above;

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• lower interest expense, primarily due to the redemption of $66 million of Ameren Missouri’s subordinated deferrable interest debentures in September 2010, Ameren Illinois’ redemptions of $150 million of senior secured notes and $40 million of first mortgage bonds in June 2011 and September 2010, respectively, and a reduction in borrowings under credit facility agreements (7 cents per share);

• reduced impairment and other charges (7 cents per share);

• higher Ameren Illinois electric rates pursuant to orders issued by the ICC in 2010 (6 cents per share);

• the absence in 2011 of a charge for the impact on deferred taxes from changes in federal health care laws (6 cents per share);

• the absence in 2011 of charges recorded in 2010 for cancelled or unrecoverable projects at Ameren Missouri (6 cents per share);

• a reduction in Ameren Missouri operations and maintenance expense related to plant maintenance as fewer costs were

incurred for major outages at coal-fired energy centers because the scope of the outages in 2011 was not as extensive as the scope of the outages conducted in 2010 (6 cents per share); and

• reduction in expense as a result of disciplined cost management efforts to align spending with regulatory outcomes and economic conditions.

The cents per share information presented above is based on average shares outstanding in 2010.

For additional details regarding our results of operations, including explanations of Margins, Other Operations and Maintenance Expenses, Impairment and Other Charges, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income and Expenses, Interest Charges, Income Taxes, and Income (Loss) from Discontinued Operations, Net of Taxes, see the major headings below.

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Below is a table of income statement components by segment for the years ended December 31, 2012, 2011, and 2010:

2012	Ameren Missouri			Ameren Illinois			Other / Intersegment Eliminations			Total
Electric margins	$	2,340		$	1,034		$	(11	)	$	3,363
Natural gas margins	75			378			(1		)	452
Other revenues	1			—			(1		)	—
Other operations and maintenance	(827		)	(684		)	(3		)	(1,514		)
Impairment and other charges	—			—			—			—
Depreciation and amortization	(440		)	(221		)	(6		)	(667		)
Taxes other than income taxes	(304		)	(130		)	(9		)	(443		)
Other income and (expenses)	49			(10		)	(6		)	33
Interest charges	(223		)	(129		)	(39		)	(391		)
Income (taxes) benefit	(252		)	(94		)	37			(309		)
Income (loss) from continuing operations	419			144			(39		)	524
Loss from discontinued operations, net of taxes	—			—			(1,498		)	(1,498		)
Net income (loss)	419			144			(1,537		)	(974		)
Net income (loss) attributable to noncontrolling interests - continuing operations	(3		)	(3		)	—			(6		)
Net income (loss) attributable to noncontrolling interests - discontinued operations	—			—			6			6
Net income (loss) attributable to Ameren Corporation	$	416		$	141		$	(1,531	)	$	(974	)
2011
Electric margins	$	2,252		$	1,087		$	24		$	3,363
Natural gas margins	79			354			(2		)	431
Other revenues	5			1			(6		)	—
Other operations and maintenance	(934		)	(640		)	(6		)	(1,580		)
Impairment and other charges	(89		)	—			(34		)	(123		)
Depreciation and amortization	(408		)	(215		)	(23		)	(646		)
Taxes other than income taxes	(296		)	(129		)	(9		)	(434		)
Other income and (expenses)	51			1			(7		)	45
Interest charges	(209		)	(136		)	(42		)	(387		)
Income (taxes) benefit	(161		)	(127		)	43			(245		)
Income (loss) from continuing operations	290			196			(62		)	424
Income from discontinued operations, net of taxes	—			—			102			102
Net income	290			196			40			526
Net income (loss) attributable to noncontrolling interests - continuing operations	(3		)	(3		)	—			(6		)
Net income (loss) attributable to noncontrolling interests - discontinued operations	—			—			(1		)	(1		)
Net income attributable to Ameren Corporation	$	287		$	193		$	39		$	519
2010
Electric margins	$	2,233		$	1,096		$	29		$	3,358
Natural gas margins	75			375			(2		)	448
Other revenues	1			—			(1		)	—
Other operations and maintenance	(931		)	(635		)	—			(1,566		)
Impairment and other charges	—			—			(64		)	(64		)
Depreciation and amortization	(382		)	(210		)	(35		)	(627		)
Taxes other than income taxes	(285		)	(128		)	(11		)	(424		)
Other income and (expenses)	70			(6		)	(8		)	56
Interest charges	(213		)	(143		)	(59		)	(415		)
Income (taxes) benefit	(199		)	(137		)	62			(274		)
Income (loss) from continuing operations	369			212			(89		)	492
Loss from discontinued operations, net of taxes	—			—			(341		)	(341		)
Net income (loss)	369			212			(430		)	151
Net income (loss) attributable to noncontrolling interests - continuing operations	(5		)	(4		)	—			(9		)
Net income (loss) attributable to noncontrolling interests - discontinued operations	—			—			(3		)	(3		)
Net income (loss) attributable to Ameren Corporation	$	364		$	208		$	(433	)	$	139

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Margins

The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins from the previous year. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as gas revenues less gas purchased for resale. The table covers the years ended December 31, 2012, 2011, and 2010. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP, and may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

2012 versus 2011	Ameren Missouri Segment			Ameren Illinois Segment			Other(a)			Ameren
Electric revenue change:
Effect of weather (estimate)(b)	$	(19	)	$	(1	)	$	—		$	(20	)
Regulated rates:
Base rates (estimate)	102			—			—			102
Formula ratemaking adjustment under IEIMA (estimate)	—			(55		)	—			(55		)
Recovery of FAC under-recovery(c)	(47		)	—			—			(47		)
Off-system revenues (included in base rates)	(131		)	—			—			(131		)
FAC prudence review disallowance	17			—			—			17
Transmission services	5			(1		)	1			5
Wholesale revenues	(13		)	(6		)	—			(19		)
Illinois pass-through power supply costs	—			(154		)	2			(152		)
Energy efficiency programs and environmental remediation cost riders	—			11			—			11
Bad debt rider	—			(4		)	—			(4		)
Hurricane Sandy relief cost recovery	7			10			—			17
Rate-regulated sales volume (excluding the impact of abnormal weather)	(6		)	(3		)	—			(9		)
Meredosia and Hutsonville energy centers	—			—			(81		)	(81		)
Other	(5		)	2			—			(3		)
Total electric revenue change	$	(90	)	$	(201	)	$	(78	)	$	(369	)
Fuel and purchased power change:
Fuel:
Meredosia and Hutsonville energy centers	$	—		$	—		$	45		$	45
Fuel, purchased power and transportation costs (included in base rates)	106			—			—			106
Recovery of FAC under-recovery(c)	47			—			—			47
Net unrealized MTM gains (losses)	1			—			—			1
Power purchase agreement settlement	24			—			—			24
Transmission over-recovery	—			(6		)	—			(6		)
Illinois pass-through power supply costs	—			154			(2		)	152
Total fuel and purchased power change	$	178		$	148		$	43		$	369
Net change in electric margins	$	88		$	(53	)	$	(35	)	$	—
Natural gas margins change:
Effect of weather (estimate)(b)	$	(2	)	$	(10	)	$	—		$	(12	)
Base rates (estimate)	2			20			—			22
Rate redesign	(5		)	—			—			(5		)
Energy efficiency programs and environmental remediation cost riders	—			8			—			8
Bad debt rider	—			(5		)	—			(5		)
Hurricane Sandy relief cost recovery	—			3			—			3
Sales volume (excluding impact of abnormal weather) and other	1			8			1			10
Net change in natural gas margins	$	(4	)	$	24		$	1		$	21

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2011 versus 2010	Ameren Missouri Segment			Ameren Illinois Segment			Other(a)			Ameren
Electric revenue change:
Effect of weather (estimate)(b)	$	(29	)	$	(7	)	$	—		$	(36	)
Regulated rates:
Base rates (estimate)	172			20			—			192
Recovery of FAC under-recovery(c)	89			—			—			89
Off-system revenues included in base rates	53			—			—			53
FAC prudence review disallowance	(17		)	—			—			(17		)
Transmission services	1			(4		)	4			1
Wholesale revenues	(43		)	9			—			(34		)
Illinois pass-through power supply costs	—			(112		)	—			(112		)
Energy efficiency programs and environmental remediation cost riders	—			6			—			6
Bad debt rider	—			(17		)				(17		)
Rate-regulated sales volume (excluding the impact of abnormal weather)	(37		)	(15		)	—			(52		)
Net unrealized MTM losses	(2		)	—			—			(2		)
Meredosia and Hutsonville energy centers	—			—			(2		)	(2		)
Other	5			(1		)	—			4
Total electric revenue change	$	192		$	(121	)	$	2		$	73
Fuel and purchased power change:
Fuel:
Meredosia and Hutsonville energy centers	$	—		$	—		$	(7	)	$	(7	)
Fuel, purchased power and transportation costs included in base rates	(84		)	—			—			(84		)
Recovery of FAC under-recovery(c)	(89		)	—			—			(89		)
Illinois pass-through power supply costs	—			112			—			112
Total fuel and purchased power change	$	(173	)	$	112		$	(7	)	$	(68	)
Net change in electric margins	$	19		$	(9	)	$	(5	)	$	5
Natural gas margins change:
Effect of weather (estimate)(b)	$	(1	)	$	(5	)	$	—		$	(6	)
Bad debt rider	—			(14		)	—			(14		)
Base rates (estimate)	5			3			—			8
Energy efficiency programs and environmental remediation cost riders	—			(1		)	—			(1		)
Sales volume (excluding impact of abnormal weather) and other	—			(4		)	—			(4		)
Net change in natural gas margins	$	4		$	(21	)	$	—		$	(17	)

(a) Primarily includes amounts for the Meredosia and Hutsonville energy centers, ATXI, and intercompany eliminations.

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

(c) Represents the change in the net fuel costs recovered under the FAC through customer rates, with corresponding offsets to fuel expense due to the amortization of a previously recorded regulatory asset.

2012 versus 2011

Ameren Corporation

Ameren's electric margins were unchanged in 2012 compared with 2011; however, its natural gas margins increased by $21 million, or 5%, in 2012 compared with 2011. These results were primarily driven by the Ameren Missouri and Ameren Illinois segments outlined further below. Ameren's electric margins also reflect the results of operations of the Meredosia and Hutsonville energy centers, which Ameren will retain when the New AER divestiture is complete. These two energy centers were inactive in 2012, which lowered revenues by $81 million, partially offset by a $45 million reduction in fuel costs.

Ameren Missouri Segment

Ameren Missouri's electric margins increased by $88 million,

or 4%, in 2012 compared with 2011. The following items had a favorable impact on Ameren Missouri's electric margins:

• Higher electric base rates, effective July 2011, which increased revenues by $102 million, offset by an increase in net base fuel expense of $25 million, which was a result of higher net base fuel cost rates approved in the 2011 MoPSC rate order. The change in net base fuel expense was the sum of the change in fuel, purchased power and transportation costs included in base rates (+$106 million) and the change in off-system revenues (-$131 million) in the above table.

• Reduced purchased power expense as a result of a FERC-ordered refund received from Entergy in 2012 relating to a power purchase agreement that expired in 2009, which increased margins by $24 million. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this

8

Current Report on Form 8-K for further information.

• Absence in 2012 of a reduction in revenues recorded in 2011 resulting from the MoPSC's FAC prudence review order the period from March 1, 2009, to September 30, 2009, which increased revenues by $17 million. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for further information.

• Recovery of labor and benefit costs associated with crews assisting with Hurricane Sandy power restoration, which increased revenues by $7 million and was fully offset by operations and maintenance costs with no overall impact on net income.

• Higher transmission services revenues primarily due to two transmission projects that went into service in second half of 2011 and were included in transmission rates in 2012, which increased revenues by $5 million.

• Summer weather conditions in 2012 were comparable to 2011, as evidenced by an increase of 1% in cooling degree-days. However, weather conditions in Ameren Missouri's service territory in 2012 were the warmest on record with 25% more cooling degree-days than normal.

The following items had an unfavorable impact on Ameren Missouri's electric margins in 2012 compared with 2011:

• Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by a 16% decrease in heating degree-days, which decreased revenues by $19 million.

• The inclusion of wholesale sales in the FAC as an offset to fuel costs beginning July 31, 2011, decreased revenues by $13 million.

• Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes that declined by 1%, partially attributable to energy efficiency measures and customer conservation efforts, which decreased revenues by $6 million.

Ameren Missouri has a FAC cost recovery mechanism that allows Ameren Missouri to recover, through customer rates, 95% of changes in fuel, 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 reviews. The MoPSC's December 2012 order authorized the inclusion of fuel additive costs and transmission revenues in the FAC starting in 2013. Ameren Missouri accrues, as a regulatory asset, fuel and purchased power costs that are greater than the amount set in base rates (FAC under-recovery). Net recovery of fuel costs under the FAC through customer rates decreased by $47 million in 2012, as compared with 2011, with corresponding offsets to fuel expense to reduce the previously recognized FAC regulatory asset.

Ameren Missouri's natural gas margins decreased by $4 million, or 5%, in 2012 compared with 2011. The following items had an unfavorable impact on Ameren Missouri's natural gas margins:

• Rate redesign, as a result of the natural gas delivery service rate order that became effective in late February 2011, allowed Ameren Missouri to recover more of its non-PGA residential revenues through a fixed monthly charge, with the remaining amounts recovered based on sales volumes, which resulted in revenues being recovered more evenly throughout the year. Revenues decreased by $5 million, because the rate redesign was not in effect for the first two months of 2011.

• Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by decrease in heating degree-days of 16%, which decreased margins by $2 million.

Ameren Missouri's natural gas margins were favorably affected by an increase in rates that became effective in February 2011, which increased margins by $2 million.

Ameren Illinois Segment

Ameren Illinois has a cost recovery mechanism for power purchased on behalf of its customers. These pass-through power costs do not affect margins. Electric revenues associated with Illinois pass-through power supply costs decreased$154 million because of lower power prices on sales and customers switching to alternative retail electric suppliers. This decrease in revenues was offset by a corresponding net decrease in purchased power expense. Ameren Illinois had $2 million in purchased power from Ameren Missouri in 2011, which is eliminated at Ameren. Ameren Illinois does not generate earnings based on the resale of power but rather on the delivery of power.

Ameren Illinois' electric margins decreased by $53 million, or 5%, in 2012 compared with 2011. The following items had an unfavorable impact on electric margins:

• The formula ratemaking adjustment related to an annual reconciliation of the revenue requirement pursuant to the IEIMA decreased revenues by $55 million. The reduction in revenues for 2012 was primarily caused by a lower allowed return on equity as the ICC's 2010 electric rate order resulted in a higher return on equity than the 2012 formula rate calculation allowed. The 2012 formula for the return on equity is equal to the 2012 average of monthly yields of 30-year United States treasury bonds plus 590 basis points. The return on equity included in Ameren Illinois' 2010 electric rate order was 10.2% whereas the 2012 IEIMA formula resulted in an 8.8% return on equity with the ability to earn above or below this amount by 50 basis points. The 2012 revenue requirement reconciliation included the impact of the September ICC order, which reduced revenues from October through December 2012 by $8 million. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for further information.

• Lower wholesale distribution revenues, primarily due to lower demand, and the recognition of a reserve for revenues subject to a refund as a result of a November 2012 FERC administrative law judge's decision, which in total decreased revenues by $6 million.  See Note 2 - Rate and Regulatory

9

Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for further information.

• Ameren Illinois accrues, as a regulatory asset or liability, transmission costs that are greater than or less than the amount set in transmission rates (transmission under-recovery or over-recovery). In 2012, Ameren Illinois over-recovered from customers its transmission costs by $6 million. As a result, Ameren Illinois reduced a previously recognized regulatory asset that had been established for an under-recovery of costs.

• Decreased recoveries through Ameren Illinois' bad debt rider, which decreased margins by $4 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense.

• Excluding the estimated impact of abnormal weather, rate-regulated sales volumes that increased by 1%, driven largely by the lower-margin industrial sector; however, margins decreased $3 million due to volume declines in the higher-margin residential and commercial sectors, partially attributable to energy efficiency measures and customer conservation efforts.

• Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by a decrease of 14% in heating degree-days, which decreased revenues by $1 million.

The following items had a favorable impact on Ameren Illinois' electric margins in 2012 compared with 2011:

• Increased recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms, which increased revenues by $11 million. See Other Operations and Maintenance Expenses in this section for information on the related offsetting increase in energy efficiency and environmental remediation costs.

• Recovery of labor and benefit costs associated with crews assisting with Hurricane Sandy power restoration, which increased revenues by $10 million, and was fully offset by operations and maintenance costs with no overall impact on net income.

• Summer weather conditions in 2012 were comparable to 2011, as evidenced by an increase of 2% in cooling degree-days. However, weather conditions in Ameren Illinois' service territory in 2012 were the warmest on record with 24% more cooling degree-days than normal.

Ameren Illinois' natural gas margins increased by $24 million, or 7%, in 2012 compared with 2011. The following items had a favorable impact on Ameren Illinois' natural gas margins:

• Increase in natural gas rates effective January 2012, which increased revenues by $20 million.

• Increased recovery of energy efficiency program costs and environmental remediation costs through Illinois cost recovery mechanisms, which increased revenues by $8 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.

• Higher sales volume and other primarily due to increased transportation sales from two large industrial customers and 1% higher residential sales volumes, excluding the impact of abnormal weather, which combined increased margins by $8 million.

• Recovery of labor and benefit costs associated with crews assisting with Hurricane Sandy gas service restoration, which increased revenues by $3 million, and was fully offset by operations and maintenance costs, with no overall impact on net income.

The following items had an unfavorable impact on Ameren Illinois' natural gas margins in 2012 compared with 2011:

• Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by a decrease in heating degree-days of 14%, which decreased margins $10 million.

• Decreased recoveries through Ameren Illinois' bad debt rider, which reduced margins by $5 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense.

2011 versus 2010

Ameren's electric margins increased $5 million, or less than 1%, in 2011 compared with 2010; however, its natural gas margins decreased $17 million, or 4%, in 2011 compared with 2010. These results were primarily driven by the Ameren Missouri and Ameren Illinois Segments outlined further below. In addition, Ameren will retain the Meredosia and Hutsonville energy centers when the new AER Divestiture is complete. These two energy centers fuel costs increased by $7 million in 2011 compared with 2010; however, revenues decreased by $2 million for the same period.

Ameren Missouri Segment

Net recovery of fuel costs under the FAC through customer rates increased by $89 million in 2011, as compared with 2010, with corresponding offsets to fuel expense to reduce the previously recognized FAC regulatory asset.

Ameren Missouri's electric margins increased by $19 million, or 1%, in 2011 compared with 2010. Ameren Missouri's electric margins were favorably affected by higher electric base rates, effective in June 2010 and July 2011 ($172 million), offset by increased net base fuel expense of $31 million, which was a result of higher net base fuel cost rates approved in the 2010 and 2011 MoPSC rate orders and higher fuel and transportation costs. The change in net base fuel expense is the sum of the change in fuel, purchased power and transportation costs included in base rates (-$84 million) and the change in off-system revenues (+$53 million) in the above table.

The following items had an unfavorable impact on Ameren Missouri's electric margins in 2011 compared with 2010:

• Lower wholesale sales due to a reduction in customers, the

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expiration of favorably priced contracts, and the inclusion of revenues from the remaining contracts as an offset to fuel costs in the FAC beginning July 31, 2011, which decreased revenues by $43 million.

• Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes declined by 1%, attributable to continued economic pressure, energy efficiency measures, and customer conservation efforts, which decreased revenues by $37 million.

• Winter weather conditions in 2011 were near normal compared to a somewhat colder-than-normal 2010, as evidenced by a 7% decrease in heating degree-days, which decreased revenues by $29 million.

• A $17 million reduction in revenues recorded in 2011 resulting from the MoPSC's order with respect to its FAC disallowance for the period from March 1, 2009 to September 30, 2009. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for further information regarding the FAC prudence review.

Ameren Missouri's natural gas margins increased by $4 million, or 5%, in 2011 compared with 2010. Ameren Missouri's natural gas margins were favorably affected by higher natural gas rates, effective February 2011, which increased margins by $5 million.

Ameren Illinois Segment

Ameren Illinois has a cost recovery mechanism for power purchased on behalf of its customers. These pass-through power costs do not affect margins. Ameren's revenues associated with Illinois pass-through power supply costs decreased $112 million because of lower power prices on sales primarily to nonaffiliated parties. These revenues were offset by a corresponding net decrease in purchased power. Ameren Illinois does not generate earnings based on the resale of power, but rather on the delivery of energy.

Ameren Illinois' electric margins decreased by $9 million, or 1%, in 2011 compared with 2010. The following items had an unfavorable impact on electric margins:

• Decreased recovery of prior years' bad debt expense through the Illinois bad debt rider, effective March 2010, which decreased margins by $17 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense.

• Continued economic pressure, energy efficiency measures, and customer conservation efforts, which decreased revenues by $15 million.

• Winter weather conditions in 2011 were near normal compared to a somewhat colder-than-normal 2010, as evidenced by a 5% decrease in heating degree-days, which decreased revenues by $7 million.

The following items had a favorable impact on Ameren Illinois' electric margins in 2011 compared with 2010:

• Higher electric delivery service rates, effective in May and November 2010, which increased margins by $20 million.

• Higher wholesale revenues, primarily due to higher rates effective April 2011, which increased revenues by $9 million.  See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for further information.

• Increased recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms, which increased margins by $6 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.

Ameren Illinois' natural gas margins decreased by $21 million, or 6%, in 2011 compared with 2010. The following items had an unfavorable impact on Ameren Illinois' natural gas margins:

• Decreased recovery of prior years' bad debt expense under the Illinois bad debt rider, effective March 2010, which decreased margins by $14 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense.

• Unfavorable winter weather conditions, as evidenced by a 5% decrease in heating degree-days, decreased revenues by $5 million. However, compared to normal, Ameren Illinois experienced in 2011 a 2% decrease in heating degree-days.

• Native load sales volumes declined by 4%, excluding the estimated impact of abnormal weather, largely in the commercial and industrial sectors, attributable to continued economic pressure, which decreased revenues by $4 million.

Ameren Illinois' gas margins were favorably affected by $3 million due to higher natural gas rates effective in May and November 2010.

Other Operations and Maintenance Expenses

2012 versus 2011

Ameren Corporation

Other operations and maintenance expenses decreased by $66 million in 2012 compared with 2011. Variations in other operations and maintenance expenses at the Ameren Missouri and Ameren Illinois segments between 2012 and 2011 are noted below. Additionally, there was a $10 million increase in stock-based compensation expense. See Note 12 - Stock-based Compensation under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information. Ameren's other operations and maintenance expenses also reflect the results of operations of the Meredosia and Hutsonville energy centers, which Ameren will retain when the New AER divestiture is complete. These two energy centers were inactive in 2012 which reduced other operations and maintenance expenses by $7 million.

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Ameren Missouri Segment

Other operations and maintenance expenses decreased by $107 million in 2012.

The following items reduced other operations and maintenance expenses between years:

• A $40 million decrease in Callaway energy center refueling and maintenance costs as there was no outage in 2012.

• A $27 million decrease in employee severance costs due to the voluntary separation program in 2011.

• A $25 million reduction in other labor costs, primarily because of staff reductions.

• A $19 million decrease in storm-related repair costs, due to fewer major storms in 2012.

• A $6 million favorable change in unrealized net MTM gains between years, resulting from changes in the market value of investments used to support Ameren's deferred compensation plans.

• A $6 million decrease in bad debt expense due to improved customer collections.

• A $4 million decrease in non-storm-related distribution maintenance expenditures, primarily due to lower repair spending.

• Disciplined cost management efforts to align spending with regulatory outcomes, policies, and economic conditions.

Other operations and maintenance expenses increased between years because of a $6 million charge in 2012 for a canceled project.

Ameren Illinois Segment

Other operations and maintenance expenses increased by $44 million in 2012.

The following items increased other operations and maintenance expenses between years:

• A $19 million increase in energy efficiency and environmental remediation costs.

• A $16 million increase in non-storm-related electric distribution maintenance expenditures due, in part, to mild winter weather in 2012 allowing crews to complete more maintenance projects.

• A $15 million increase in other labor costs, primarily because of staff additions due to the requirements of the IEIMA.

• An $11 million increase in transmission and distribution expenses, primarily because of National Electric Safety Code repairs, which are nonrecoverable operating expenditures under formula ratemaking pursuant to the IEIMA, and pipeline integration compliance.

• A $6 million increase in employee benefit costs, primarily due to increased pension expense.

The following items reduced other operations and maintenance expenses between years:

• A $14 million decrease in storm-related repair costs, due to fewer major storms in 2012.

• A $9 million decrease in bad debt expense, including $5 million due to improved customer collections and $4 million due to adjustments related to prior years under the bad debt rider. Expenses recorded under the Ameren Illinois bad debt rider mechanism were recovered through customer billings, and so were offset by increased revenues, with no overall effect on net income.

2011 versus 2010

Ameren Corporation

Other operations and maintenance expenses increased by $14 million in 2011 compared with 2010. Variations in other operations and maintenance expenses at the Ameren Missouri and Ameren Illinois segments between 2011 and 2010 are noted below.

Ameren Missouri Segment

Other operations and maintenance expenses increased by $3 million in 2011.

The following items increased other operations and maintenance expenses between years:

• Recognition of $27 million of employee severance costs related to the voluntary separation plan in 2011.

• A $21 million increase in storm-related repair costs, due to major storms in 2011.

• A reduction in other operations and maintenance expenses in 2010 by $11 million for the May 2010 MoPSC rate order, which resulted in the recording of regulatory assets related to 2009 employee severance costs and storm costs.

• An unfavorable change of $5 million in unrealized net MTM adjustments between years, resulting from changes in the market value of investments used to support Ameren's deferred compensation plans.

The following items reduced other operations and maintenance expenses between years:

• Plant maintenance costs decreased by $23 million, primarily because the scope of the outages in 2011 was not as extensive as in 2010. Costs associated with the 2011 refueling and maintenance outage at Ameren Missouri's Callaway energy center were consistent with costs incurred for the 2010 refueling and maintenance outage.

• Charges in 2010 of $22 million because of canceled or unrecoverable projects that did not recur in 2011.

• A $9 million decrease in employee benefit costs, primarily because of adjustments under the pension and postretirement benefit cost tracker.

• Disciplined cost management efforts to align spending with regulatory outcomes and economic conditions.

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Ameren Illinois Segment

Other operations and maintenance expenses increased by $5 million in 2011.

The following items increased other operations and maintenance expenses between years:

• A $13 million increase in storm-related repair costs, due to major storms in 2011.

• Energy efficiency and environmental remediation costs increased by $5 million.

• Injuries and damages expenses were higher by $4 million because of increased claims.

• Expenses of $3 million associated with the electric rate case in 2011 were written-off because the rate case was withdrawn after passage of the IEIMA.

• A reduction in other operations and maintenance expenses in 2010 of $3 million for a May 2010 ICC rate order, which resulted in the recording of a regulatory asset related to 2009 employee severance costs.

The following items reduced other operations and maintenance expenses between years:

• A $19 million reduction in bad debt expense. Adjustments of $31 million under the bad debt rider mechanism were partially offset by higher uncollectible expense.

• A reduction of $5 million in non-storm-related distribution maintenance expenditures due, in part, to cost management efforts.

Impairment and Other Charges

Ameren Corporation

Ameren will retain the Meredosia and Hutsonville energy centers when the New AER divestiture is completed.

In December 2011, Genco ceased operations of its Meredosia and Hutsonville energy centers. As a result, Ameren recorded noncash pretax asset impairment charges 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.

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.

Ameren Missouri Segment

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.

Depreciation and Amortization

2012 versus 2011

Ameren Corporation

Depreciation and amortization expenses increased by $21 million in 2012 compared with 2011. Variations in depreciation and amortization expenses at the Ameren Missouri and Ameren Illinois segments between 2012 and 2011 are noted below. Additionally, there was a $5 million reduction in depreciation and amortization expenses at Ameren Services, due to the retirement of computer equipment in 2011. Also, Ameren will retain the Meredosia and Hutsonville energy centers when the New AER divestiture is completed. The long-lived asset impairments recorded during the fourth quarter of 2011 caused a reduction in the carrying value of net plant assets for the two energy centers which reduced depreciation and amortization expenses by $10 million.

Ameren Missouri Segment

Depreciation and amortization expenses increased by $32 million in 2012, primarily because of increased depreciation and amortization expenses associated with the new scrubbers at the Sioux energy center (depreciation expense began with the effective date of the July 2011 electric rate order) and other capital additions.

Ameren Illinois Segment

Depreciation and amortization expenses increased by $6 million in 2012, primarily due to transmission and distribution infrastructure additions.

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2011 versus 2010

Ameren Corporation

Depreciation and amortization expenses increased by $19 million in 2011 compared with 2010. Variations in depreciation and amortization expenses at the Ameren Missouri and Ameren Illinois segments between 2011 and 2010 are noted below. Additionally, there was an $8 million reduction in depreciation and amortization expenses at Ameren Services, primarily because computer equipment became fully-depreciated during 2011.

Ameren Missouri Segment

Depreciation and amortization expenses increased by $26 million in 2011, primarily because of increased depreciation and amortization expenses resulting from the installation of the new scrubbers at the Sioux energy center and other capital additions. Additionally, an increase in Ameren Missouri's annual depreciation rates as a result of the 2010 MoPSC electric rate order resulted in higher depreciation and amortization expenses.

Ameren Illinois Segment

Depreciation and amortization expenses increased by $5 million in 2011, primarily because of capital additions.

Taxes Other Than Income Taxes

2012 versus 2011

Ameren Corporation

Taxes other than income taxes increased by $9 million in 2012 compared with 2011. Variations in taxes other than income taxes at the Ameren Missouri and Ameren Illinois segments between 2012 and 2011 are noted below.

Ameren Missouri Segment

Taxes other than income taxes increased by $8 million in 2012, because of higher property taxes resulting from increased state and local assessments in 2012, the recording of a refund for protested distributable taxes in 2011, and the subsequent recording in December 2012 based on the MoPSC electric rate order to return this refund to customers. These unfavorable items more than offset a decrease in payroll taxes between years.

Ameren Illinois Segment

Taxes other than income taxes were comparable between years, as a reduction in gross receipts taxes resulting from decreased sales offset higher property taxes due to increased rates.

2011 versus 2010

Ameren Corporation

Taxes other than income taxes increased by $10 million in 2011 compared with 2010. Variations in taxes other than income

taxes at the Ameren Missouri and Ameren Illinois segments between 2011 and 2010 are noted below.

Ameren Missouri Segment

Taxes other than income taxes increased by $11 million in 2011, primarily because of increased property taxes, due to higher state and local assessments and higher tax rates, and to higher gross receipts taxes from increased revenues.

Ameren Illinois Segment

Taxes other than income taxes were comparable between years. Increased property taxes in 2011, primarily due to higher tax rates, were mitigated by lower corporate franchise taxes in 2011 as a result of the Ameren Illinois Merger.

Other Income and Expenses

2012 versus 2011

Ameren Corporation

Other income, net of expenses, decreased by $12 million in 2012 compared with 2011. Variations in other income, net of expenses, at the Ameren Missouri and Ameren Illinois segments between 2012 and 2011 are noted below.

Ameren Missouri Segment

Other income, net of expenses, was comparable between years. Increased donations offset an increase in interest income, resulting from the interest paid by Entergy on the amount it overcharged Ameren Missouri under a power purchase agreement. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for further information on the power purchase agreement with Entergy.

Ameren Illinois Segment

Ameren Illinois had net other expenses of $10 million in 2012, compared with net other income of $1 million in 2011. Donations increased by approximately $10 million because of a one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and a $1 million annual donation for customer assistance programs pursuant to the IEIMA, because Ameren Illinois participated in the formula ratemaking process in 2012.

2011 versus 2010

Ameren Corporation

Other income, net of expenses, decreased by $11 million in 2011 compared with 2010. Variations in other income, net of expenses, at the Ameren Missouri and Ameren Illinois segments between 2011 and 2010 are noted below.

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Ameren Missouri Segment

Other income, net of expenses, decreased by $19 million in 2011, primarily because of reduced allowance for equity funds used during construction. Allowance for equity funds used during construction was higher in 2010, primarily due to the new scrubbers being constructed at Ameren Missouri's Sioux energy center, which were placed in service in late 2010.

Ameren Illinois Segment

Other income, net of expenses, increased by $7 million in 2011, primarily because of reduced expenses associated with customer assistance programs.

Interest Charges

2012 versus 2011

Ameren Corporation

Interest charges increased by $4 million in 2012 compared with 2011. Variations in interest charges at the Ameren Missouri and Ameren Illinois segments between 2012 and 2011 are noted below. Additionally, $2 million in reduced credit facility borrowings and commercial paper issuances at Ameren lowered interest charges.

Ameren Missouri Segment

Interest charges increased by $14 million in 2012, primarily because Ameren Missouri no longer recorded an allowance for funds used during construction for pollution control equipment installed at its Sioux energy center when the cost of the equipment was placed in customer rates beginning July 31, 2011, and an increase in interest charges associated with uncertain tax positions.

Ameren Illinois Segment

Interest charges decreased by $7 million in 2012, primarily because of the redemption of $150 million of senior secured notes in June 2011.

2011 versus 2010

Ameren Corporation

Interest charges decreased by $28 million in 2011 compared with 2010. Variations in interest charges at the Ameren Missouri and Ameren Illinois segments between 2011 and 2010 are noted below. Additionally, $13 million in reduced credit facility borrowings at Ameren lowered interest charges.

Ameren Missouri Segment

Interest charges decreased by $4 million in 2011, primarily because of a reduction in interest charges associated with uncertain tax positions of $6 million, the redemption of $66 million of subordinated deferrable interest debentures in September 2010, and reduced amortization of credit facility fees. Offsetting

these favorable items was a reduction in interest charges in 2010 due to the May 2010 MoPSC electric rate order. The rate order resulted in a reduction of interest charges of $10 million in 2010, through the recording of a regulatory asset for recovery of bank credit facility fees incurred in 2009.

Ameren Illinois Segment

Interest charges decreased by $7 million in 2011, primarily because of the redemption of $150 million of senior secured notes in June 2011 and the redemption of $40 million of first mortgage bonds in September 2010.

Income Taxes

The following table presents effective income tax rates for Ameren's business segments and for the Ameren Companies for the years ended December 31, 2012, 2011, and 2010:

	2012	2011	2010
Ameren	37%	37%	36%
Ameren Missouri	37%	36%	35%
Ameren Illinois	40%	39%	39%

2012 versus 2011

Ameren Corporation

Ameren's effective tax rate was comparable between 2012 and 2011. The effective tax rate increases for Ameren Missouri and Ameren Illinois noted below were offset primarily by a decrease related to permanent tax benefits from company-owned life insurance. Variations in effective tax rates at Ameren Missouri and Ameren Illinois between 2012 and 2011 are noted below.

Ameren Missouri Segment

Ameren Missouri's effective tax rate was higher primarily because of an increase in reserves for uncertain tax positions in 2012, compared to a decrease in 2011. Additionally, the effective tax rate increased because of the decreased impact of the amortization of property-related regulatory assets and liabilities, and estimated tax credits on higher pretax income in 2012 compared with 2011.

Ameren Illinois Segment

Ameren Illinois' effective tax rate was higher primarily because of the favorable impact of recording the adjustment to deferred tax assets due to the Illinois statutory income tax rate increase in 2011.

2011 versus 2010

Ameren Corporation

Ameren's effective tax rate was higher in 2011 than 2010, primarily due to changes in reserves for uncertain tax positions, along with lower favorable net amortization of property-related regulatory assets and liabilities, offset, in part, by the effect of the change in the tax treatment of retiree health care costs in 2010.

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Variations in effective tax rates at the Ameren Missouri and Ameren Illinois segments between 2011 and 2010 are noted below.

Ameren Missouri Segment

Ameren Missouri's effective tax rate was higher, primarily because of lower favorable net amortization of property-related regulatory assets and liabilities in 2011 compared to 2010, offset, in part, by the effect of the change in the tax treatment of retiree health care costs in 2010 and changes to reserves for uncertain tax positions.

Ameren Illinois Segment

Ameren Illinois' effective tax rate was comparable between years.

Income (Loss) from Discontinued Operations, Net of Taxes

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH, which Ameren expects will close 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 under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information regarding these divestitures and the asset impairments discussed below. 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.

Long-lived Asset Impairments

In 2012, Ameren recorded noncash pretax impairment charges of $2.6 billion to reduce the carrying values of all but one of Merchant Generation's coal and natural gas-fired energy centers. 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' long-lived assets. As a result of the December 2012 determination, Ameren concluded that the estimated undiscounted cash flows through the period in which Ameren expects to continue to have a significant economic interest in 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 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 and therefore was unimpaired. Following the impairment charge, the net book value of Ameren's Merchant Generation long-lived assets was $748 million as of December 31, 2012.

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. For the fourth quarter 2012 long-lived asset impairment test, Ameren used a discount rate of 10% for the coal-fired energy centers, 10.5% for the combined cycle energy center, and 11.5% for natural gas-fired energy centers, used a terminal year earnings multiple ranging from 4.5 to 6 depending on the energy center's fuel type and installed pollution control equipment, and estimated that the duration of ownership for each energy center was less than five years, with one energy center's duration of ownership being less than two years. Holding all other assumptions constant, if the discount rate had been one percentage point higher, or if the terminal year earnings multiple had been one point lower, or if the duration of ownership for each energy center was one year less than estimated, the fourth quarter 2012 impairment charge would have been $30 million to $110 million higher. As discussed above, the Joppa coal-fired energy center's estimated undiscounted cash flows exceeded its carrying value; however, using the same assumptions to estimate the fair value of that energy center would result in an estimated fair value that approximated its carrying value as of December 31, 2012.

In early 2012, the observable market price for power for delivery in 2012 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. 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

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AERG's Duck Creek energy center to its estimated fair value during the first quarter of 2012. Similar types of assumptions described above for the fourth quarter 2012 long-lived asset impairment test were used in this first quarter 2012 test. In this first quarter 2012 test, Ameren used a discount rate of 9.5% and estimated each energy center's useful life based on its physical life. The estimated useful life assumption in this first quarter 2012 test was based on energy center specific facts.

The 2012 long-lived asset impairment charges were expected to reduce 2013 depreciation expense by approximately $75 million. However, 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.

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 charge of $37 million to reduce the carrying value of the Medina Valley energy centers to its estimated fair value. In 2012, Ameren sold the Medina Valley energy center and recognized a $10 million gain on the sale.

Goodwill Impairment

During 2010, Ameren also recorded a noncash pretax goodwill impairment charge of $420 million, which represented all of the goodwill assigned to Ameren's Merchant Generation reporting unit. The goodwill impairment recorded in 2010 was caused by a sustained decline in market prices for electricity, by industry market multiples becoming observable at lower levels than previously estimated, and by the possibility that more stringent environmental regulations would be enacted.

Intangible Assets Impairment

Prior to 2010, Merchant Generation 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 that all of its SO₂ emission allowances would be used in operations. Therefore, during 2010, Ameren recorded a noncash pretax impairment charge of $68 million to reduce the carrying value of the Merchant Generation segment's SO₂ emission allowances to their estimated fair value. In July 2011, the EPA issued the final 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.

Ameren recorded a noncash pretax impairment charge of $2 million in 2011 relating to Merchant Generation’s emission

allowances.

Non-Impairment Operating Results

Merchant Generation's electric margins decreased by $116 million, or 18%, in 2012 compared with 2011. Merchant Generation's electric margins were unfavorably impacted by lower spot market prices, an EEI sales contract in 2011 that was not supplied in 2012, and by higher fuel prices, primarily due to higher commodity costs associated with new coal supply agreements. Merchant Generation's average capacity factor decreased to 66% in 2012, compared with 73% in 2011, because of lower power prices. Merchant Generation's equivalent availability factor remained unchanged at 85% in 2012 and 2011.

Merchant Generation's electric margins decreased by $99 million, or 13%, in 2011 compared with 2010. Merchant Generation's electric margins were unfavorably impacted by lower sales prices, due to reductions in higher-margin sales resulting from the expiration of the 2006 auction power supply agreements on May 31, 2010, and lower market prices and by higher fuel prices, primarily due to higher commodity and transportation costs. Merchant Generation's average capacity factor decreased to 73% in 2011, compared with 74% in 2010, and equivalent availability factor decreased to 85% in 2011, compared with 87% in 2010.

Other operations and maintenance expenses decreased by $12 million in 2012 compared with 2011 at Merchant Generation, as reduced plant maintenance costs of $16 million, due to fewer outages, increased property sale gains of $3 million, as well as disciplined cost management more than offset charges for canceled projects of $12 million. Other operations and maintenance expenses were comparable between 2011 and 2010 at Merchant Generation. Increased employee benefit costs, primarily pension costs, and higher plant maintenance costs resulting from increased planned outages at AERG mitigated the favorable impact of property sale gains at Genco.

Depreciation and amortization expenses decreased by $31 million in 2012 compared with 2011 at Merchant Generation, primarily because of a 2011 change in estimates related to asset retirement obligations. Additionally, the long-lived asset impairments recorded during the first and fourth quarters of 2012 caused a reduction in the carrying value of net plant assets and thus depreciation expense. Depreciation and amortization expenses were comparable between 2011 and 2010 at Merchant Generation.

Interest charges decreased by $8 million in 2012 compared with 2011 at Merchant Generation, primarily because of increased capitalized interest due to the Newton energy center scrubber project. Interest charges decreased by $19 million in 2011 compared with 2010 at Merchant Generation, primarily because of the maturity and repayment of $200 million of Genco senior unsecured notes in November 2010 and because of reduced intercompany borrowings at AERG.

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Merchant Generation's effective tax rate was higher in 2012 compared with 2011, primarily because of the decreased impact of the permanent book tax differences on a large pretax loss in 2012, along with favorable change in the reserves for uncertain tax positions in 2011. Merchant Generation's effective tax rate was higher in 2011 compared with 2010, primarily because the impact of the nondeductible goodwill impairment charge in 2010, partially offset by lower benefits from state tax credits related to capital investments, and favorable changes in the reserves for uncertain tax positions in 2011.

LIQUIDITY AND CAPITAL RESOURCES

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

standards, and other improvements. Ameren intends to finance those capital expenditures and investments in its rate-regulated businesses with a blend of equity and debt so that it maintains a capital structure of approximately 50% to 55% equity, assuming constructive regulatory environments. Ameren plans to implement its long-term financing plans for debt, equity, or equity-linked securities to finance its operations appropriately, to fund scheduled debt maturities, and to maintain financial strength and flexibility.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 16 - Divestiture Transactions and Discontinued Operations under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information. As a result of the transaction agreement with IPH and Ameren’s plan to sell the Elgin, Gibson City, and Grand Tower energy centers to a third-party, the Merchant Generation business was classified as discontinued operations for all periods presented in this report. While it remains a business of Ameren, the Merchant Generation segment will seek to fund its operations internally and therefore will seek not to rely on financing from Ameren or external, third-party sources. The Merchant Generation segment will seek to defer or reduce capital and operating expenses, sell certain assets, and take other actions, as necessary, to fund its operations internally while maintaining safe and reliable operations. The transaction agreement with IPH contains customary covenants of Ameren that AER will be operated in the ordinary course prior to closing. However, if Ameren does not complete its divestiture of New AER, Ameren will continue to reduce, and ultimately eliminate, the Merchant Generation segment’s reliance on Ameren’s financial support.

The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2012, 2011, and 2010:

	Net Cash Provided By Operating Activities						Net Cash (Used In) Investing Activities									Net Cash (Used In) Financing Activities
	2012		2011		2010		2012			2011			2010			2012			2011			2010
Continuing operations	$	1,399	$	1,512	$	1,403	$	(1,153	)	$	(949	)	$	(1,015	)	$	(426	)	$	(1,020	)	$	(698	)
Discontinued operations	291		366		420		(157		)	(99		)	(81		)	—			(100		)	(106		)

Cash Flows from Operating Activities

2012 versus 2011

Cash from operating activities associated with continuing operations decreased in 2012, compared with 2011. The following items contributed to the decrease in cash from operating activities during 2012, compared with 2011:

• Cash flows associated with Ameren Missouri's under-recovered FAC costs, which decreased by $161 million. Recoveries outpaced deferrals in 2011 by $87 million, while deferrals outpaced recoveries in 2012 by $74 million.

• The premiums paid to debt holders in connection with the repurchase of multiple series of Ameren Missouri and Ameren Illinois senior secured notes totaled $138 million. See Note 5 - Long-term Debt and Equity Financings under

Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information.

• An $82 million decrease in cash collections from customer receivables, excluding the impacts of the receipt of funds from, and deposits into, court registries discussed separately below, primarily caused by milder weather in December 2011, compared with December 2010.

• Income tax payments related to continuing operations of $8 million in 2012, compared with income tax refunds of $59 million in 2011. The 2011 refund resulted primarily from an IRS settlement, while the 2012 payment was caused by the purchase of state tax credits. Ameren did not make material federal income tax payments in either period because of accelerated deductions authorized by economic stimulus legislation and other deductions.

• A $40 million increase in coal inventory at Ameren Missouri primarily due to additional tons held in inventory because generation levels were below expected levels due to market

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conditions, the absence in 2012 of flooding that impeded coal deliveries in 2011, increased coal prices, and milder weather conditions in early 2012.

• A $22 million increase in energy efficiency expenditures, primarily for Ameren Illinois customer programs, which are recovered through customer billings over time.

The following items partially offset the decrease in cash from operating activities during 2012, compared with 2011:

• Electric and natural gas margins, as discussed in Results of Operations, which increased by $75 million, excluding impacts of noncash MTM transactions and Ameren Illinois' noncash IEIMA formula ratemaking adjustment.

• Ameren Missouri's receipt of $37 million from the Stoddard County Circuit Court's registry and the Cole County Circuit Court's registry as the MoPSC's 2009 and 2010 electric rate orders were upheld on appeals. Additionally, $24 million fewer Ameren Missouri receivables were paid into the court registries in 2012 in connection with the electric rate order appeals. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information.

• A $52 million decrease in pension and postretirement plan contributions. In 2011, Ameren Illinois contributed to Ameren's postretirement benefit plan trust an incremental $100 million in excess of Ameren Illinois' annual postretirement net periodic cost for regulatory purposes.

• A $50 million decrease in the cost of natural gas held in storage because of lower prices.

• A $35 million decrease in major storm restoration costs.

• A $26 million decrease in taxes other than income tax payments, primarily related to Ameren Missouri, caused by the timing of property tax payments at each year end, partially offset by higher assessed property tax values.

• A $21 million reduction in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center, caused by the absence of a refueling outage in 2012.

• A $21 million increase in natural gas commodity over-recovered costs under the PGA, primarily related to Ameren Illinois.

• A $20 million decrease in payments related to the MISO liability due, in part, to fewer payments required for December 2011 purchases compared to the payments required for December 2010 purchases.

• A net $5 million decrease in collateral posted with counterparties due, in part, to changes in the market prices of power and natural gas and in contracted commodity volumes.

Cash from operating activities associated with discontinued operations decreased in 2012, compared with 2011, primarily attributable to a $104 million decrease in electric margins, excluding impacts of noncash unrealized MTM activity, as discussed in Results of Operations, partially offset by an $18 million decrease in coal inventory, primarily due to continued focus inventory reductions, partially offset by increased coal prices.

2011 versus 2010

Cash from operating activities associated with continuing operations increased in 2011, compared with 2010. The following items contributed to the increase in cash from operating activities during 2011, compared with 2010:

• Ameren Missouri’s regulatory asset for FAC under-recovery, which decreased by $216 million as more deferred costs were recovered from customers during 2011.

• Trade accounts receivable and unbilled revenues balances at Ameren Missouri and Ameren Illinois decreased, primarily because of milder weather in the fourth quarter of 2011, compared with the fourth quarter of 2010. Those same weather conditions caused accounts payable balances to MISO and natural gas suppliers to decrease as less power and natural gas was purchased. Additionally, during 2011, MISO shortened the length of its settlement terms for all of its members. The new terms resulted in an acceleration of payments that previously would not have been made until 2012. These factors resulted in a net increase of $128 million in cash from operating activities in 2011 compared with 2010.

• A net $106 million decrease in collateral posted with counterparties due, in part, to a reduction in the market price of natural gas and in contracted volumes.

• A $26 million decrease in interest payments related to continuing operations, primarily due to the long-term debt redemptions and a reduction in Ameren’s borrowings under its credit facility agreements, which resulted in an $11 million reduction in interest payments.

• An $11 million reduction in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center caused primarily by the timing of the 2011 outage compared with the 2010 outage, which had unpaid liabilities as of December 31, 2011.

The following items reduced the increase in cash from operating activities during 2011, compared with 2010:

• A $108 million increase in pension and postretirement benefit plan contributions. Ameren Illinois contributed to Ameren’s postretirement benefit VEBA trust an incremental $100 million in excess of Ameren Illinois’ annual postretirement net periodic cost for regulatory purposes.

• A $62 million decrease in income tax refunds. The 2010 refund resulted primarily from a 2009 change in tax treatment of electric generation plant expenditures. The 2011 refund resulted primarily from casualty loss deductions due to an Internal Revenue Service audit settlement. Ameren did not make any federal income tax payments in 2011 because of accelerated deductions authorized by economic stimulus legislation, use of its net operating loss carryforwards, and other deductions.

• A $55 million decrease associated with the December 2005 Taum Sauk incident, primarily as a result of insurance recoveries received in 2010, but not in 2011.

• A $34 million increase in major storm restoration costs.

• A $28 million increase in taxes other than income tax

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payments that related to higher assessed property tax values for energy center enhancements, county property tax rate increases, and the timing of property tax payments at each year end for Ameren Missouri. Ameren Illinois incurred an increase in electricity distribution and invested capital tax payments resulting from the tiered rate structure for the merged entity.

• Reduced collections as more utility customers were past due on their bills on December 31, 2011, than on December 31, 2010. Additionally, write-offs of customer receivable balances increased because of economic conditions.

• An $18 million increase in Ameren Missouri receivables held in court registries under the appeals of the MoPSC’s 2009 and 2010 rate orders. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information.

• A $16 million decrease in Ameren Illinois’ electric purchased power commodity over-recovered costs.

• A $15 million increase in energy efficiency expenditures for new customer programs. The Ameren Illinois amount is recovered through customer billings over time.

• An $11 million decrease in natural gas commodity over-recovered costs under the PGA, primarily in Illinois.

• Electric and natural gas margins, as discussed in Results of Operations, which decreased by $10 million, excluding impacts of noncash MTM transactions.

• A $7 million increase in preliminary study expenditures, primarily at Ameren Missouri for environmental compliance testing.

Cash from operating activities associated with discontinued operations decreased in 2011, compared with 2010, primarily attributable to a $76 million decrease in electric margins, excluding impacts of noncash unrealized MTM activity, as discussed in Results of Operations. Income tax refunds related to discontinued operations were $2 million in 2011, compared with income tax payments of $30 million in 2010. The 2011 refund was primarily due to an increase in accelerated depreciation deductions authorized by the economic stimulus legislation. The 2010 payments were primarily due to 2009 return payments in addition to estimated payments as well as timing of intercompany tax payments made through the tax allocation agreement.

Pension Funding

Ameren’s pension plans are funded in compliance with income tax regulations and to meet federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at 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 with actual investment performance, changes in interest rates, changes in our assumptions, any pertinent changes in government regulations, and any voluntary contributions. In 2012, Ameren contributed $128 million to its pension plans. See Note

11 - Retirement Benefits under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information.

Cash Flows from Investing Activities

2012 versus 2011

Cash used in investing activities associated with continuing operations increased by $204 million during 2012, compared with 2011. Capital expenditures increased $182 million primarily because of increased expenditures for maintenance and reliability, boiler, and turbine projects, which more than offset a decrease in storm restoration costs. Cash flows used in investing activities also increased because of a $29 million increase in nuclear fuel expenditures due to timing of purchases, which was partially offset by a receipt of $18 million federal tax grants related to renewable energy construction projects.

Cash flows used in investing activities associated with discontinued operations increased during 2012, compared with 2011. Capital expenditures increased $26 million as a result of increased expenditures related to the scrubber project at the Newton energy center, which more than offset a reduction in maintenance and upgrade project expenditures due to the timing of energy center outages. In 2012, proceeds of $16 million were received from the sale of the Medina Valley energy center’s net property and plant. In 2011, Genco received $45 million of proceeds from the sale of its interest in the Columbia CT energy center.

2011 versus 2010

Cash used in investing activities associated with continuing operations decreased by $66 million during 2011, compared with 2010, primarily attributable to a $60 million decrease in capital expenditures. Reductions in capital expenditures caused by the completion of two scrubbers at Ameren Missouri’s Sioux energy center in 2010 were offset, in part, by an increase in storm-related repair costs and an increase in electric transmission investments.

Cash flows used in investing activities associated with discontinued operations increased during 2011, compared with 2010. Capital expenditures increased $51 million as a result of increased spending for energy center scrubber projects and boiler projects. Genco received proceeds of $45 million and $18 million in 2011 and 2010, respectively, from the sale of Genco's interest in its Columbia CT energy center.

Capital Expenditures

Capital expenditures from continuing operations were $1,063 million, $881 million, and $941 million for the years ended December 31, 2012, 2011, and 2010.

Ameren’s 2012 capital expenditures principally consisted of the following expenditures at its subsidiaries. Ameren Missouri spent $30 million on the replacement of the Callaway reactor head, scheduled to be replaced during the 2013 Callaway refueling and maintenance outage and $23 million on a boiler

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upgrade project. Ameren Illinois spent $27 million on IEIMA-related expenditures. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois, as well as to fund various energy center upgrades.

Ameren’s 2011 capital expenditures principally consisted of the following expenditures at its subsidiaries. Ameren Missouri spent $24 million on building its Maryland Heights energy center and $31 million for storm-related repair costs. Ameren Illinois incurred storm-related repair costs of $20 million. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois, as well as to fund various energy center upgrades.

Ameren’s 2010 capital expenditures principally consisted of the following expenditures at its subsidiaries. Ameren Missouri spent $130 million toward two scrubbers at its Sioux energy center, which were completed in 2010. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois, as well as to fund various energy center upgrades.

The following table estimates Ameren's capital expenditures that will be incurred from 2013 through 2017, including construction expenditures, allowance for funds used during construction for Ameren's rate-regulated utility businesses, and estimated expenditures for compliance with known and existing environmental regulations.

	2013			2014 - 2017					Total
Ameren Missouri	$	720		$	2,250	-	$	3,045	$	2,970	-	$	3,765
Ameren Illinois	695			2,400		-	3,250		3,095		-	3,945
ATXI	60			965		-	1,310		1,025		-	1,370
Other(a)	(5		)	60		-	80		55		-	75
Ameren	$	1,470		$	5,675	-	$	7,685	$	7,145	-	$	9,155

(a) Includes the elimination of intercompany transfers.

Ameren Missouri’s estimated capital expenditures include transmission, distribution, and generation-related investments, as well as expenditures for compliance with the environmental regulations discussed below. Ameren Illinois’ estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments, and estimated capital expenditures incremental to historical average electric delivery capital expenditures to modernize its distribution system pursuant to the IEIMA. Until the uncertainty surrounding how the IEIMA will ultimately be implemented is removed, Ameren Illinois is slowing its IEIMA capital spending. Even though it is proceeding on a slower schedule, Ameren Illinois intends to meet its IEIMA capital spending requirements. For additional information on the IEIMA, see Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K. Estimated capital expenditures for ATXI include the MISO-approved multi-value transmission projects.

We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other things. Additionally, we continually review the reliability of our transmission and distribution systems, expected capacity needs, and opportunities for transmission investments. The timing and amount of investments could vary because of changes in expected capacity, the condition of transmission and distribution systems, and our ability and willingness to pursue transmission investments, among other things. Any changes in future generation, transmission or distribution needs could result in significant capital expenditures or losses being incurred, which could be material.

Environmental Capital Expenditures

Ameren will incur significant costs in future years to comply with existing and known federal and state regulations including those requiring the reduction of SO₂, NO_x, and mercury emissions from Ameren Missouri's coal-fired energy centers.

See Note 15 - Commitments and Contingencies under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for a discussion of existing environmental laws and regulations that affect, or may affect, our facilities and capital costs to comply with such laws and regulations, as well as our assessment of the potential impacts of the EPA’s proposed regulation of CCR and the finalized MATS, as of December 31, 2012.

Cash Flows from Financing Activities

2012 versus 2011

During 2012, we replaced and extended the expiration of our credit agreements. We reduced our reliance on short-term debt while maintaining adequate cash balances for working capital needs.

Ameren's net cash used in financing activities associated with continuing operations decreased during 2012, compared with 2011. Repayments of net short-term debt and credit agreement borrowings decreased by $333 million in 2012, compared with 2011. The decrease in cash provided by operating activities in 2012, combined with the increase in capital expenditures, resulted in less cash available to fund financing activities. However, Ameren was still able to repay all outstanding short-term debt that existed at the beginning of the year in 2012. In 2012, Ameren subsidiaries issued $885 million in senior debt and used the proceeds, together with other available cash, to repurchase, redeem, and repay existing long-term indebtedness of $754 million and to pay related premiums. In 2011, Ameren Illinois funded the $150 million maturity of its senior secured notes with cash on hand and operating cash flows. There was also a reduction in refunds of advances previously received from generators of $73 million due to project completion in 2011. In 2011, common stock issued for DRPlus and the 401(k) plan increased cash flows from financing activities by $65 million. In 2012, Ameren shares were purchased in the open market for

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DRPlus and the 401(k) plan, resulting in noncash financing activity of $7 million due to the timing of DRPlus common stock dividend funding.

Net cash used in financing activities associated with discontinued operations decreased during 2012, compared with 2011. In 2012, working capital and investing requirements were met without utilizing financing activities. In 2011, surplus net cash from operating activities was utilized to repay $100 million of short-term borrowing obligations.

2011 versus 2010

During 2011, we reduced our reliance on borrowings from short-term debt and credit agreements, and we reduced long-term debt outstanding while maintaining adequate cash balances for working capital needs.

Ameren’s cash used in financing activities associated with continuing operations increased in 2011, compared with 2010. During 2011, Ameren’s cash flow from operating activities of $1.5 billion exceeded its capital expenditures of $0.9 billion and common stock dividend requirements of $375 million. Ameren used this cash as well as cash on hand to repay $481 million of short-term debt and credit agreement borrowings, to redeem

$155 million of long-term debt, and to repay $73 million of advances received from generators due to project completion. During 2010, Ameren redeemed $110 million of long-term debt and $52 million of preferred stock.

Net cash used in financing activities associated with discontinued operations decreased during 2011, compared with 2010. In 2011, surplus net cash from operating activities was utilized to reduce reliance on credit facility borrowings. In 2010, we repaid at maturity $200 million of Genco's 8.35% senior notes at maturity. The 2010 cash outlay was offset, in part, by credit facility borrowings of $100 million.

Credit Agreement Borrowings and Liquidity

The liquidity needs of Ameren are typically supported through the use of available cash, short-term intercompany borrowings, and drawings under committed bank credit agreements, or commercial paper issuances. See Note 4 - Short-term Debt and Liquidity under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information on credit agreements, short-term borrowing activity, commercial paper issuances, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements.

The following table presents the committed 2012 Credit Agreements of Ameren and the credit capacity available under such agreements, considering reductions for letters of credit, as of December 31, 2012:

	Expiration	Borrowing Capacity		Credit Available
2012 Missouri Credit Agreement(a)(b)	November 2017	$	1,000	$	1,000
2012 Illinois Credit Agreement(a)(b)	November 2017	1,100		1,100
Less: Letters of credit		(c)		(9		)
Total		$	2,100	$	2,091

(a) Certain Ameren subsidiaries not party to the 2012 Credit Agreements may access these credit agreements through intercompany borrowing arrangements.

(b) Each credit agreement expires on November 14, 2017. The borrowing sublimits of Ameren Missouri and Ameren Illinois will mature and expire on November 13, 2013, subject to extension 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 each credit agreement, but in no event later than November 14, 2017. Ameren Missouri and Ameren Illinois will seek state regulatory approval to extend the maturity date of their borrowing sublimits under the 2012 Credit Agreements to November 14, 2017.

(c) Not applicable.

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 borrowings under Ameren Missouri's commercial paper program, and the 2012 Illinois Credit Agreement is available to support borrowings under Ameren Illinois' commercial paper program.

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.

Subject to applicable regulatory short-term borrowing authorizations, these credit arrangements are also available to other Ameren non-state-regulated subsidiaries through direct short-term borrowings from Ameren and by most of Ameren’s non-rate-regulated subsidiaries, including, but not limited to, Ameren Services, through a non-state-regulated subsidiary money pool agreement. Ameren has money pool agreements with and among its subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. In addition, a unilateral borrowing agreement

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among Ameren, Ameren Illinois, and Ameren Services enables Ameren Illinois to make short-term borrowings directly from Ameren. Pursuant to the terms of the unilateral borrowing agreement, 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 the authorization from the ICC. Ameren Illinois did not borrow under the unilateral borrowing agreement during 2012 or 2011. Ameren Services is responsible for operation and administration of the money pool agreements. See Note 4 - Short-term Debt and Liquidity under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for a detailed explanation of the money pool arrangements and the unilateral borrowing agreement.

The issuance of short-term debt securities by Ameren's

utility subsidiaries is subject to approval by FERC under the Federal Power Act. In April 2012, FERC issued an order authorizing the issuance of up to $1 billion of short-term debt securities for Ameren Missouri. The authorization was effective immediately and terminates on March 31, 2014. On September 20, 2012, FERC issued an order authorizing the issuance of up to $1 billion of short-term debt securities. The authorization was effective as of October 1, 2012 and terminates on September 30, 2014.

The issuance of short-term debt securities by Ameren is not subject to approval by any regulatory body.

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

Long-term Debt and Equity

The following table presents the issuances of common stock and the issuances, redemptions, repurchases, and maturities of long-term debt and preferred stock (net of any issuance discounts) for the years 2012, 2011, and 2010 for the Ameren Companies. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 5 - Long-term Debt and Equity Financings under Exhibit 99.4, Item 8, of this Current Report on Form 8-K.

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	Month Issued, Redeemed, Repurchased or Matured	2012		2011		2010
Issuances
Long-term debt
Ameren Missouri:
3.90% Senior secured notes due 2042	September	$	482	$	—	$	—
Ameren Illinois:
2.70% Senior secured notes due 2022	August	400		—		—
Total Ameren long-term debt issuances		$	882	$	—	$	—
Common stock
Ameren:
DRPlus and 401(k)	Various	$	—	$	65	$	80
Total common stock issuances		$	—	$	65	$	80
Total Ameren long-term debt and common stock issuances		$	882	$	65	$	80
Redemptions, Repurchases and Maturities
Long-term debt
Ameren Missouri:
City of Bowling Green capital lease (Peno Creek CT)	Various	$	5	$	5	$	4
5.25% Senior secured notes due 2012	September	173		—		—
6.00% Senior secured notes due 2018	September	71		—		—
6.70% Senior secured notes due 2019	September	121		—		—
5.10% Senior secured notes due 2018	September	1		—		—
5.10% Senior secured notes due 2019	September	56		—		—
7.69% Series A subordinated deferrable interest debentures due 2036	September	—		—		66
Ameren Illinois:
6.625% Senior secured notes due 2011	June	—		150		—
9.75% Senior secured notes due 2018	August	87		—		—
6.25% Senior secured notes due 2018	August	194		—		—
2000 Series A 5.50% pollution control revenue bonds due 2014	August	51		—		—
7.61% Series 1997-2 first mortgage bonds due 2017	September	—		—		40
6.20% Series 1992B due 2012	November	1		—		—
Total Ameren long-term debt redemptions, repurchases and maturities		$	760	$	155	$	110
Preferred stock
Ameren Missouri:
$7.64 Series	August	$	—	$	—	$	33
Ameren Illinois:
4.50% Series	August	—		—		11
4.64% Series	August	—		—		8
4.08% Series(a)	September	—		—		7
4.20% Series(a)	September	—		—		5
4.26% Series(a)	September	—		—		4
4.42% Series(a)	September	—		—		3
4.70% Series(a)	September	—		—		5
7.75% Series(a)	September	—		—		9
Total Ameren preferred stock redemptions and repurchases		$	—	$	—	$	85
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities		$	760	$	155	$	195

(a) In September 2010, Ameren contributed to the capital of Ameren Illinois (formerly IP), without the payment of any consideration, all of the IP preferred stock owned by Ameren ($33 million). IP canceled these preferred shares.

In June 2012, Ameren filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in June 2015.

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)

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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.

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

Indebtedness Provisions and Other Covenants

See Note 4 - Short-term Debt and Liquidity and Note 5 - Long-term Debt and Equity Financings under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our bank credit and term loan agreements and in certain of the Ameren Companies’ indentures and articles of incorporation.

At December 31, 2012, the Ameren Companies were in compliance with the provisions and covenants contained within their credit agreements, indentures, and articles of incorporation.

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

Discontinued Operations

AER’s operating results and operating cash flows are significantly affected by changes in market prices for power, which have significantly decreased over the past few years. Under the provisions of its indenture, described in Note 16 - Divestiture Transactions and Discontinued Operations, in Exhibit 99.4, Item 8, of this Current Report on Form 8-K, Genco may not borrow additional funds from external, third-party sources if its interest coverage ratio is less than a specified minimum or if its debt-to-capital ratio is greater than a specified maximum. Beginning in the first quarter of 2013, Genco’s interest coverage ratio fell to a level less than the specified minimum level required for external borrowings, and Genco expects the ratio to remain less than this minimum level through at least 2015. As a result, Genco’s ability to borrow additional funds from external, third-party sources is restricted. Genco’s indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool. However, borrowings from the money

pool are subject to Ameren’s control, and if a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time. While it remains a business of Ameren, the Merchant Generation segment, including Genco, seeks to fund its operations internally and therefore seeks not to rely on financing from Ameren or external, third-party sources.

Should a financing need arise, Genco's sources of liquidity include available cash on hand, a return of money pool advances, and money pool borrowings at the discretion of Ameren. On March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which was subject to FERC approval. Based on current projections, excluding the amount received related to the put option, Genco expects operating cash flows to approximate nonoperating cash flow requirements in 2013 and daily working capital needs to be sufficiently covered by cash on hand.

Dividends

Ameren paid to its shareholders common stock dividends totaling $382 million, or $1.60 per share, in 2012, $375 million, or $1.555 per share, in 2011, and $368 million, or $1.54 per share, in 2010.

The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. The board of directors has not set specific targets or payout parameters when declaring common stock dividends. However, as it has done in the past, the board of directors is expected to consider various issues, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. On February 8, 2013, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 40 cents per share, payable on March 29, 2013, to stockholders of record on March 13, 2013.

Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends in certain circumstances.

Ameren Illinois’ articles of incorporation require its dividend payments on 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.

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

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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 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. No dividends were paid by Genco in 2012, 2011, or 2010. See Note 16 - Divestiture Transactions and Discontinued Operations, in Exhibit 99.4, Item 8, of this Current Report on Form 8-K of this report for additional information on Genco's indenture provisions.

Ameren Missouri and Ameren Illinois, as well as 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.

In its application for the FERC orders approving the Ameren Illinois Merger and the AERG distribution, Ameren committed itself to maintain a minimum of 30% equity in its capital structure at Ameren Illinois following the Ameren Illinois Merger and the AERG distribution.

At December 31, 2012, Ameren, Ameren Missouri and Ameren Illinois were not restricted from paying dividends.

At December, 31, 2012, the amount of restricted net assets of wholly owned subsidiaries of Ameren that may not be distributed to Ameren in the form of a loan or dividend was $2 billion.

Ameren Missouri and Ameren Illinois have issued preferred stock, which provides for cumulative preferred stock dividends. Each company’s board of directors considers the declaration of the preferred stock dividends to shareholders of record on a certain date, stating the date on which the dividend is payable and the amount to be paid. See Note 5 - Long-term Debt and Equity Financings under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for further detail concerning the preferred stock issuances.

Contractual Obligations

The following table presents our contractual obligations as of December 31, 2012. See Note 11 - Retirement Benefits under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for information regarding expected minimum funding levels for our pension plans. These expected pension funding amounts are not included in the table below. In addition, routine short-term purchase order commitments are not included.

	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		After 5 Years
Long-term debt and capital lease obligations(a)(b)	$	6,167	$	355	$	654	$	1,076	$	4,082
Interest payments(c)	3,688		369		624		546		2,149
Operating leases(d)	138		19		28		28		63
Other obligations(e)	7,613		1,563		2,556		1,835		1,659
Total cash contractual obligations	$	17,606	$	2,306	$	3,862	$	3,485	$	7,953

(a) Excludes fair-market value adjustments of long-term debt of $4 million.

(b) Excludes unamortized discount and premium of $14 million.

(c) The weighted-average variable-rate debt has been calculated using the interest rate as of December 31, 2012.

(d) Amounts related to certain land-related leases have indefinite payment periods. The annual obligation of $2 million for these items is included in the Less than 1 Year, 1 - 3 Years, and 3 - 5 Years columns.

(e) See Other Obligations in Note 15 - Commitments and Contingencies under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for discussion of items included herein.

As of December 31, 2012, the amount of unrecognized tax benefits under the authoritative accounting guidance for uncertain tax positions was $156 million. It is reasonably possible to expect that the settlement of an unrecognized tax benefit will result in an underpayment or overpayment of tax and related interest. However, there is a high degree of uncertainty with respect to the timing of cash payments or receipts associated with unrecognized tax benefits. The amount and timing of certain

payments or receipts is not reliably estimable or determinable at this time. See Note 13 - Income Taxes under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for information regarding the unrecognized tax benefits and related liabilities for interest expense.

Off-Balance-Sheet Arrangements

At December 31, 2012, none of the Ameren Companies had

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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 under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for Ameren (parent) guarantees on behalf of its subsidiaries.

Credit Ratings

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

The following table presents the principal credit ratings of the Ameren Companies by Moody’s, S&P, and Fitch effective on March 1, 2013:

	Moody’s	S&P	Fitch
Ameren:
Issuer/corporate credit rating	Baa3	BBB-	BBB
Senior unsecured debt	Baa3	BB+	BBB
Commercial paper	P-3	A-3	F2
Ameren Missouri:
Issuer/corporate credit rating	Baa2	BBB-	BBB+
Secured debt	A3	BBB+	A
Ameren Illinois:
Issuer/corporate credit rating	Baa2	BBB-	BBB-
Secured debt	A3	BBB+	BBB+
Senior unsecured debt	Baa2	BBB-	BBB

The cost of borrowing under our credit facilities can also increase or decrease depending upon the credit ratings of the borrower. A credit rating is not a recommendation to buy, sell, or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.

Collateral Postings

Any adverse change in credit ratings relating to Ameren's continuing operations may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power, and natural gas supply, among other things, resulting in a negative impact on earnings. Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts at December 31, 2012, were $71 million. Cash collateral posted by external counterparties with Ameren at December 31, 2012 was $2 million. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at December 31, 2012, could have resulted in Ameren being required to post additional collateral or other assurances for certain trade obligations amounting to $155 million.

Changes in commodity prices could trigger additional collateral postings and prepayments at current credit ratings. If

market prices were 15% higher than December 31, 2012, levels in the next 12 months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren could be required to post additional collateral or other assurances for certain trade obligations up to $6 million. If market prices were 15% lower than December 31, 2012, levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren could be required to post additional collateral or other assurances for certain trade obligations up to $35 million.

See Note 16 - Divestiture Transactions and Discontinued Operations under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for information regarding Ameren's transaction agreement to divest New AER to IPH. Upon the divestiture of New AER to IPH, the transaction agreement requires Ameren to maintain its financial obligations with respect to all credit support provided to New AER for all transactions entered into prior to the closing of such divestiture for up to 24 months after the closing. The permitted forms of credit support for each counterparty agreement could include one or more of the following: cash, a letter of credit, a parent company guarantee, or other credit support alternatives. Ameren's exposure related to the continuation of credit support provided to New AER after the divestiture closing date is dependent upon the transactions and counterparty agreements that AER and its subsidiaries have in effect as of the divestiture closing date. IPH shall indemnify Ameren for any payments Ameren makes pursuant to these credit support obligations if the counterparty does not return the posted collateral to Ameren. IPH's indemnification obligation will be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren Corporation pursuant to which Dynegy will, among other things, guarantee IPH's indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions). See Note 14 - Related Party Transactions with New AER under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for information regarding Ameren (parent) guarantees.

Cash collateral postings and prepayments by AER and its subsidiaries with external parties, including postings related to exchange-traded contracts, at December 31, 2012, were $27 million. Cash collateral posted by external counterparties with AER at December 31, 2012 were $3 million. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at Ameren at December 31, 2012, could have resulted in Ameren being required to post additional collateral or other assurances for certain trade obligations of AER and its subsidiaries amounting to $90 million. Changes in commodity prices could trigger additional collateral postings and prepayments for AER and its subsidiaries based on Ameren’s current credit ratings. If market prices were 15% higher than December 31, 2012, levels in the next 12 months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren could be required to post additional collateral or other assurances for certain trade obligations of New AER up to $168 million. If market prices were 15% lower than December 31, 2012, levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity

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contracts, then Ameren could be required to post additional collateral or other assurances for certain trade obligations of New AER up to $117 million.

OUTLOOK

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

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

Rate-Regulated Operations

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

• In December 2012, the ICC issued an order with respect to Ameren Illinois' update IEIMA filing approving an electric delivery service revenue requirement that was a $70 million decrease from the requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The new rates became effective on January 1, 2013. We believe that Ameren Illinois' participation in the performance-based formula ratemaking framework pursuant to the IEIMA will better enable Ameren Illinois to earn its allowed return on equity for its electric delivery service business. This framework is expected to give Ameren Illinois the earnings predictability to invest in modernizing its distribution system. However, the ICC's orders in 2012 for Ameren Illinois' initial and update filings jeopardize Ameren Illinois' ongoing ability to implement infrastructure improvements to the extent and on the timetable envisioned in the IEIMA. Ameren Illinois has appealed both of the ICC's 2012 electric rate orders to the courts and is also seeking a legislative solution to address the ICC's implementation of the IEIMA. Although Ameren Illinois intends to meet its IEIMA capital spending requirements, it is proceeding on a slower investment

schedule than previously contemplated until the uncertainty surrounding how the IEIMA will ultimately be implemented is removed.

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

• Ameren Illinois' 2012 revenue requirement under the IEIMA 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. Consequently, Ameren recorded a $55 million regulatory liability 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 allowed 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 January 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service by $50 million. In an attempt to reduce regulatory lag, Ameren Illinois used a future test year, 2014, in this proceeding. A decision in this proceeding is required by December 2013.

• 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 2011 electric rate order. The annual increase also includes $80 million for recovery of the costs associated with energy efficiency programs under the MEEIA. The remaining annual increase of $96 million approved by the MoPSC was for energy infrastructure investments and other non-fuel costs, including $10 million for increased pension and other post-employment benefit costs and $6 million for increased amortization of regulatory assets. The new rates became effective on January 2, 2013.

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

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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 based on the achievement of certain energy efficiency goals, including approximately $19 million if 100% of Ameren Missouri's energy efficiency goals are achieved during the three-year period, with the potential to earn more if energy savings exceeds those goals. 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.

• As they continue to experience cost recovery pressures, Ameren Missouri and Ameren Illinois expect to seek regular electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. Ameren Missouri and Ameren Illinois will also seek legislative solutions to address cost recovery pressures. These pressures include a weak economy, customer conservation efforts, the impacts of energy efficiency programs, increased investments and expected future investments for environmental compliance, system reliability improvements, and new baseload capacity, including renewable energy requirements. Increased investments also result in higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs, higher property and income taxes, and higher insurance premiums as a result of insurance market conditions and industry loss experience, among other things.

• The MoPSC issued an order, in April 2011, with respect to its review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. The order required Ameren Missouri to refund $18 million, including $1 million for interest, to customers related to pretax earnings associated with certain long-term partial requirements sales made by Ameren Missouri after the loss of Noranda's load in a severe ice storm in January 2009. Ameren Missouri appealed this decision to the Cole County Circuit Court, which overturned the MoPSC's April 2011 order. The Cole County Circuit Court decision is being appealed by the MoPSC to the Missouri Court of Appeals. It is possible that the MoPSC could order additional refunds of approximately $25 million related to pretax earnings associated with these long-term partial requirements sales in periods after September 2009, and this could result in a charge to earnings in the period in which such an order is received. Separately, Ameren Missouri filed a request with the MoPSC in July 2011 for an accounting authority order that would allow Ameren Missouri to recover fixed costs totaling $36 million due to the loss of load caused by the severe 2009 ice storm in a future electric rate case. If the courts ultimately rule in favor of Ameren Missouri's position regarding the classification of the long-term partial requirements sales, Ameren Missouri would no longer seek to recover from customers the sum covered by the accounting authority order.

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

• Ameren Missouri's Callaway energy center's next scheduled refueling and maintenance outage will be in the spring of 2013. The expected duration of this outage is approximately 40 days. During a scheduled outage, which occurs every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC resulting in limited impact to earnings.

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

• Ameren intends to allocate its capital to those investment opportunities with the highest expected risk-adjusted returns. Ameren believes that because of its strategic location in the country, electric transmission may provide it with such an opportunity. MISO has approved three projects, which will be developed by ATXI. The first project, Illinois Rivers, involves the building of a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. Design and planning work on the first sections of this project have begun and right-of-way acquisitions are scheduled to commence in late 2013 after receipt of a certificate of public convenience and necessity, which ATXI requested from the ICC in November 2012. Construction is expected to begin in 2014. The first sections of the Illinois Rivers project are expected to be in service in 2016. The last section of this project is expected to be completed in 2019. The Spoon River project in northwest Illinois and the Mark Twain project in northeast Missouri are the other two projects approved by MISO in its current transmission expansion plan. These two projects are expected to be completed in 2018. The estimated total investment in these three projects is expected to be more than $1.3 billion through 2019. FERC has approved transmission rate incentives for the three MISO approved projects as well as for the Big Muddy River project. The Big Muddy River project, located primarily in southern Illinois, is being evaluated for inclusion in MISO's transmission expansion plans. Separate from the ATXI projects discussed above, Ameren Illinois expects to invest approximately $1 billion in electric transmission assets over the next five years to address load growth and reliability requirements.

• In November 2012, FERC approved a forward-looking rate

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

• For additional information regarding recent rate orders and related appeals, pending requests filed with state and federal regulatory commissions, the FAC prudence review and related appeal, Taum Sauk matters, and separate FERC orders impacting Ameren Missouri and Ameren Illinois, see Note 2 - Rate and Regulatory Matters, Note 10 - Callaway Energy Center, and Note 15 - Commitments and Contingencies under Exhibit 99.4, Item 8, of this Current Report on Form 8-K.

Discontinued Operations

• Ameren no longer considers the Merchant Generation segment to be a core component of its future business strategy. As a result, Ameren intends to exit its Merchant Generation segment before the end of the previously estimated useful lives of that segment's long-lived assets. In consideration of this determination, Ameren has begun planning to reduce, and ultimately to eliminate, the Merchant Generation segment's, including Genco's, reliance on Ameren's financial support and shared services support.

• On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 16 - Divestiture Transactions and Discontinued Operations under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information. Under the terms of the transaction agreement, Ameren is required to operate its Merchant Generation business in the ordinary course through the transaction closing date, which is expected to occur in the fourth quarter of 2013. However, if Ameren does not complete its divestiture of New AER, Ameren will continue to reduce, and ultimately eliminate, the Merchant Generation segment’s reliance on Ameren’s financial support.

• Completion of the divestiture of New AER to IPH was subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC. On October 11, 2013, Ameren received FERC approval for the divestiture of New AER to IPH. In August 2013, the FCC approved the license transfers. Separately, as a condition to IPH’s obligation to complete the acquisition of New AER, the Illinois Pollution Control Board must approve the transfer to IPH of, or otherwise approve a variance in favor of IPH on the same terms as, AER’s variance of the Illinois MPS discussed in more detail below. 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 below for further discussion regarding the initial variance granted to AER in September 2012 extending compliance dates for SO₂ emission levels contained in the MPS.

• 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. On October 11, 2013, Ameren received FERC approval for Genco's sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley.

• 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 discontinued operations presentation, Ameren suspended recording depreciation on these assets in March 2013.

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

• Based on current projections for 2013, excluding the put option receipts, AER expects its operating cash flows to approximate its nonoperating cash flow requirements in 2013. Included in this 2013 projection, AER expects to receive income tax benefits through the tax allocation agreement with Ameren and its non-AER affiliates of approximately $65 million. These estimates may change significantly depending on the taxable income or loss of Ameren and each of its subsidiaries and also assume Ameren's continued ownership of AER through 2013.

• The Merchant Generation segment expects to have available generation from its coal-fired energy centers of 31 million megawatthours in any given year. However, based on currently expected power prices, the Merchant Generation segment expects to generate approximately 27.5 million megawatthours in 2013, with approximately 95% of this generation expected to be from coal-fired energy centers.

• Power prices in the Midwest affect the amount of revenues and cash flows the Merchant Generation segment can realize by marketing power into the wholesale and retail markets. Ameren's Merchant Generation segment is adversely affected by the declining market price of power for any unhedged generation. Market prices for power have decreased over the past several years, especially sharply during the first quarter of 2012.

• As of December 31, 2012, Marketing Company had hedged approximately 25.5 million megawatthours of Merchant Generation's expected generation for 2013, at an average price of $36 per megawatthour. For 2014, Marketing Company had hedged approximately 14 million megawatthours of Merchant Generation's forecasted generation sales at an average price of $38 per megawatthour. For 2015, Marketing Company had hedged approximately 6.5 million megawatthours of Merchant Generation's forecasted generation sales at an average price of $40 per megawatthour. Any unhedged forecasted generation will be exposed to market prices at the time of

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sale. As a result, any new physical or financial power sales may be at price levels lower than previously experienced and lower than the value of existing hedged sales.

• To further reduce cash flow volatility, Merchant Generation seeks to hedge fuel costs consistent with power sales. As of December 31, 2012, for 2013 Merchant Generation had hedged fuel costs for approximately 25 million megawatthours of coal and up to 27 million megawatthours of base transportation at about $23 per megawatthour. For 2014, Merchant Generation had hedged fuel costs for approximately 13 million megawatthours of coal and up to 21 million megawatthours of base transportation at about $24 per megawatthour. For 2015, Merchant Generation had hedged fuel costs for approximately 6 million megawatthours of coal and up to 20 million megawatthours of base transportation at about $26 per megawatthour.

• In June 2012, FERC approved MISO's proposal to establish an annual capacity market within the RTO. MISO's inaugural annual capacity auction will be held in March 2013 for the June 2013 to May 2014 planning year. Participation in MISO's capacity auction is voluntary for load-serving entities as they will continue to be able to plan to meet all of their resource requirements outside of the auction, including through self-supply and/or bilateral contracts.   

• The Merchant Generation segment continues to seek revenue growth opportunities. One such opportunity is Marketing Company's ability to sell additional electric capacity into PJM. Capacity market prices within PJM are higher than capacity market prices within MISO. In addition to the capacity related to Genco's Elgin energy center, which is located within PJM, Marketing Company expects to sell additional capacity associated with 681 megawatts of PJM-approved transmission capacity from MISO to PJM. This includes 84 megawatts of transmission capacity associated with AERG energy centers from October 2011 forward, and an additional 301 megawatts and 296 megawatts of transmission capacity associated with AERG and Genco energy centers, respectively, from June 2015 forward. Another revenue growth opportunity is Marketing Company's efforts to sell power to residential and small commercial customers in Illinois. Marketing Company is actively pursuing sales to customers choosing the state of Illinois municipal aggregation alternative for electric power supply. Marketing Company's sales to municipal aggregation customers at retail prices provide margins above the current wholesale market prices. Marketing Company will attempt to expand the volume of its sales to residential and small commercial customers through the municipal aggregation initiative.

• 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. 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 order also established a schedule of milestones for completion of

various aspects of the installation and completion of the scrubber project 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.

• Upon the divestiture of New AER, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture and provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. See Note 14 - Related Party Transactions with New AER under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information.

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

Liquidity and Capital Resources

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

• As of December 31, 2012, Ameren had approximately $605 million in federal income tax net operating loss carryforwards (Ameren Missouri - $175 million and Ameren Illinois - $175 million) and $87 million in federal income tax credit carryforwards (Ameren Missouri - $11 million and Ameren Illinois - $- million). These carryforwards are expected to offset income tax liabilities for Ameren Missouri into 2014, and into 2015 for Ameren and Ameren Illinois, consistent with the tax allocation agreement.

• In December 2011, the IRS issued new guidance in the form of temporary regulations on the treatment of amounts paid to acquire, produce or improve tangible property and dispositions of such property with respect to electric transmission, distribution, and generation assets as well as natural gas transmission and distribution assets. These new rules are required to be implemented no later than January 1, 2014. This new guidance may change how Ameren determines whether expenditures related to plant and equipment are deducted as repairs or capitalized for income tax purposes. Until Ameren completes its evaluation of the new guidance, Ameren cannot estimate its impact on Ameren's results of operation, financial position, and liquidity.

• The American Taxpayer Relief Act of 2012, enacted into law on January 2, 2013, includes provisions accelerating the depreciation of certain property for income tax purposes.

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Qualifying property placed into service in 2013 is eligible for 50% bonus depreciation. It is expected that additional bonus depreciation deductions in 2013 will, after the use of net operating loss and tax credit carryforwards, decrease Ameren's income tax payments in 2015 by approximately $120 million. In addition, if these deductions had been taken into account at December 31, 2012, the amount of current accumulated deferred income tax assets would have decreased by approximately $120 million for Ameren with a corresponding decrease in long-term accumulated deferred income tax liabilities.

• In November 2012, the Ameren Companies entered into multiyear credit agreements that cumulatively provide $2.1 billion of credit through November 14, 2017. See Note 4 - Short-term Debt and Liquidity under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information regarding the 2012 Credit Agreements. Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital or financing plans.

• Ameren investments required to achieve compliance with known environmental laws and regulations relating to continuing operations from 2013 to 2022 are expected to be more than $1.1 billion. Ameren continues to closely monitor

pending laws and regulations to determine the most appropriate investment approach. Some energy centers may be refueled, retired, replaced or mothballed depending on environmental laws and regulations and market conditions. Any pollution control investments will result in decreased energy center availability during construction and significantly higher ongoing operating expenses. Any pollution control investments at Ameren Missouri are expected to be recoverable from ratepayers, subject to prudence reviews. Regulatory lag may materially affect the timing of such recovery and returns on the investments, and therefore affect our cash flows and related financing needs.

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

REGULATORY MATTERS

See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K.

ACCOUNTING MATTERS

Critical Accounting Estimates

Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. These estimates involve judgments regarding many factors that in and of themselves could materially affect the financial statements and disclosures. We have outlined below the critical accounting estimates that we believe are most difficult, subjective, or complex. Any change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.

Accounting Estimate Uncertainties Affecting Application

Regulatory Mechanisms and Cost Recovery

We defer costs in accordance with authoritative accounting guidance, and make investments that they assume will be collected in future rates.

• Regulatory environment and external regulatory decisions and requirements

• Anticipated future regulatory decisions and their impact

• Impact of deregulation, rate freezes, prudency reviews, and opposition during the ratemaking process and ability to recover costs

• Ameren Illinois' assessment of and ability to estimate the current year’s electric delivery service costs to be reflected in revenues and recovered from customers in a subsequent year under the IEIMA performance-based formula ratemaking process.

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Basis for Judgment

We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions where we operate and any other factors that may indicate whether cost recovery is probable. If facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery or that plant assets are probable of disallowance, we record a charge to earnings, which could be material. Ameren Illinois estimates its annual revenue requirement pursuant to the IEIMA for interim periods by using internal forecasted information, such as projected operations and maintenance expenses, depreciation expense, taxes other than income taxes, and rate base, as well as published forecasted data regarding that year's monthly average yields of the 30-year United States treasury bonds. Ameren Illinois estimates its annual revenue requirement as of December 31^st of each year using that year's actual operating results and assesses the probability of recovery of or refund to customers that the ICC will order at the end of the following year. Variations in costs incurred, investments made, or orders by the ICC or courts can result in a subsequent change in Ameren Illinois' estimate. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for quantification of these assets for each of the Ameren Companies.

Derivative Financial Instruments

We account for derivative financial instruments and measure their fair value in accordance with authoritative accounting guidance, which requires the identification and classification of a derivative and its fair value. See Commodity Price Risk and Fair Value of Contracts in Quantitative and Qualitative Disclosures About Market Risk under Exhibit 99.3, Item 7A, Note 7 - Derivative Financial Instruments and Note 8 - Fair Value Measurements under Exhibit 99.4, Item 8, of this Current Report on Form 8-K.

• Our ability to identify derivatives

• Our ability to assess whether derivative contracts qualify for the NPNS exception

• Our ability to consume or produce notional values of derivative contracts

• Market conditions in the energy industry, especially the effects of price volatility and liquidity

• Valuation assumptions on longer-term contracts due to lack of observable inputs

• Effectiveness of derivatives that have been designated as hedges

• Counterparty default risk

Basis for Judgment

We evaluate contracts to determine whether they contain derivatives. Determining whether or not a contract qualifies as a derivative under authoritative accounting guidance requires us to exercise significant judgment in interpreting the definition of a derivative and applying that definition. 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. We determine whether to exclude the fair value of certain derivatives from valuation under the NPNS provisions of authoritative accounting guidance after assessing our intent and ability to physically deliver commodities purchased and sold. Further, our forecasted purchases and sales also support our designation of some fair valued derivative instruments as cash flow hedges. Fair value of our derivatives is measured in accordance with authoritative accounting guidance, which provides a fair value hierarchy that prioritizes inputs to valuation techniques. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When we do not have observable inputs, we use certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risks inherent in the inputs to the valuation. Our valuations also reflect our own assessment of counterparty default risk, guided by the best internal and external information available.

Valuation of Long-Lived Assets and Asset Retirement Obligations

We periodically assess the carrying value of our long-lived assets to determine whether they are impaired. We also review for the existence of asset retirement obligations. If an asset retirement obligation is identified, we determine its fair value and subsequently reassess and adjust the obligation, as necessary.

• Changes in business, industry, laws, technology, or economic and market conditions

• Valuation assumptions and conclusions, including an appropriate discount rate and terminal year earnings multiple.

• Our assessment of market participants

• Estimated useful lives or duration of ownership of our significant long-lived assets

• Actions or assessments by our regulators

• Identification of an asset retirement obligation and assumptions about the timing of asset removals

Basis for Judgment

Whenever events or changes in circumstances indicate a valuation may have changed, we use various methodologies that we believe market participants would use to determine valuations and discounted, undiscounted, and probabilistic discounted cash flow models with multiple operating scenarios. The identification of asset retirement obligations is conducted through the review of legal documents and

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interviews. See Note 1 - Summary of Significant Accounting Policies under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for quantification of our asset retirement obligations. See Impairment and Other Charges in Management's Discussion and Analysis of Financial Condition and Results of Operations herein, and Note 16 - Divestiture Transactions and Discontinued Operations and Note 17 - Impairment and Other Charges under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information of our long-lived asset impairment evaluation and charges recorded.

Benefit Plan Accounting

Based on actuarial calculations, we accrue costs of providing future employee benefits in accordance with authoritative accounting guidance regarding benefit plans. See Note 11 - Retirement Benefits under Exhibit 99.4, Item 8, of this Current Report on Form 8-K.

• Future rate of return on pension and other plan assets

• Valuation inputs and assumptions used in the fair value measurements of plan assets excluding those inputs that are readily observable

• Interest rates used in valuing benefit obligations

• Health care cost trend rates

• Timing of employee retirements and mortality assumptions

• Ability to recover certain benefit plan costs from our ratepayers

• Changing market conditions that may affect investment and interest rate environments

• Impacts of the health care reform legislation enacted in 2010

Basis for Judgment

Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension and other postretirement benefit plan assets is based on our consistent application of assumption-setting methodologies and our review of available historical, current, and projected rates, as applicable. See Note 11 - Retirement Benefits under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for sensitivity of Ameren's benefit plans to potential changes in these assumptions.

Accounting for Contingencies

We make judgments and estimates in recording and disclosing liabilities for claims, litigation, environmental remediation, the actions of various regulatory agencies, or other matters that occur in the normal course of business. We record a loss contingency when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. A gain contingency is not recorded until realized or realizable.

• Estimating financial impact of events

• Estimating likelihood of various potential outcomes

• Regulatory and political environments and requirements

• Outcome of legal proceedings, settlements or other factors

• Changes in regulation, expected scope of work, technology or timing of environmental remediation

Basis for Judgment

The determination of a loss contingency requires significant judgment as to the expected outcome of each contingency in future periods. In making the determination as to the amount of potential loss and the probability of loss, we consider all available evidence including the expected outcome of potential litigation. If no estimate is better than another within our range of estimates, we record as our best estimate of a loss the minimum value of our estimated range of outcomes. As additional information becomes available, we reassess the potential liability related to the contingency and revise our estimates. In our evaluation of legal matters, management consults with legal counsel and relies on analysis of relevant case law and legal precedents. See Note 2 - Rate and Regulatory Matters, Note 10 - Callaway Energy Center, and Note 15 - Commitments and Contingencies under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for information on the Ameren Companies' contingencies.

Accounting for Income Taxes

Based on authoritative accounting guidance, we record the provision for income taxes, deferred tax assets and liabilities and a valuation allowance against net deferred tax assets, if any. See Note 13 - Income Taxes under Exhibit 99.4, Item 8, of this Current Report on Form 8-K.

• Changes in business, industry, laws, technology, or economic and market conditions affecting forecasted financial condition and/or results of operations

• Estimates of the amount and character of future taxable income

• Enacted tax rates applicable to taxable income in years in which temporary differences are recovered or settled

• Effectiveness of implementing tax planning strategies

• Changes in income tax laws

• Results of audits and examinations of filed tax returns by taxing authorities

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Basis for Judgment

The reporting of tax-related assets requires the use of estimates and significant management judgment. Deferred tax assets are recorded representing future effects on income taxes for temporary differences between the bases of assets for financial reporting and tax purposes. Although management believes current estimates for deferred tax assets are reasonable, actual results could differ from these estimates based on a variety of factors including change in forecasted financial condition and/or results of operations, change in income tax laws or enacted tax rates, the form, structure, and timing of asset or stock sales or dispositions, and results of audits and examinations of filed tax returns by taxing authorities. Valuation allowances against deferred tax assets are recorded when management concludes it is more likely than not such asset will not be realized in future periods. Accounting for income taxes also requires that only tax benefits for positions taken or expected to be taken on tax returns that meet the more-likely-than-not recognition threshold can be recognized or continue to be recognized. Management evaluates each position solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized. At any period end, and as new developments occur, management will reevaluate its tax positions. See Note 13 - Income Taxes under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for the amount of deferred tax assets and uncertain tax positions recorded at December 31, 2012.

Impact of Future Accounting Pronouncements

See Note 1 - Summary of Significant Accounting Policies under Exhibit 99.4, Item 8, of this Current Report on Form 8-K.

EFFECTS OF INFLATION AND CHANGING PRICES

Ameren’s rates for retail electric and natural gas utility service are regulated by the MoPSC and the ICC. Nonretail electric rates are regulated by FERC. Rate regulation is generally based on the recovery of historical or projected costs. As a result, revenue increases could lag behind changing prices. Ameren Illinois elected to participate in the performance-based formula ratemaking process pursuant to the IEIMA for its electric delivery service business. Ameren Illinois’ participation in this formula ratemaking process will terminate if the average residential rate increases by more than 2.5% annually from June 2011 through May 2014. The average residential rate includes generation service, which is outside of Ameren Illinois’ control. Ameren Illinois is required to purchase all of its power through procurement processes administered by the IPA. The cost of procured power can be affected by inflation. Within the IEIMA formula, the monthly average yields of 30-year United States treasury bonds are the basis for Ameren Illinois’ return on equity. Therefore, there is a direct correlation between the yield of United States treasury bonds, which are affected by inflation, and the earnings of Ameren Illinois’ electric distribution business. Inflation affects our operations, earnings, stockholders’ equity, and financial performance.

The current replacement cost of our utility plant substantially exceeds our recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical costs through depreciation might not be adequate to replace the plant in future years.

Ameren Missouri recovers the cost of fuel for electric generation and the cost of purchased power by adjusting rates as allowed through the FAC. Ameren Illinois recovers power supply costs from electric customers by adjusting rates through a rider mechanism to accommodate changes in power prices.

Ameren Missouri, Ameren Illinois and ATXI are affected by changes in the cost of electric transmission services. FERC

regulates the rates charged and the terms and conditions for electric wholesale and unbundled retail transmission services. Because they are members of MISO, Ameren Missouri's, Ameren Illinois' and ATXI's transmission rates are calculated in accordance with the rate formulas contained in MISO's FERC-approved tariff. Under the MISO OATT, a portion of the revenue requirement related to certain projects eligible for cost sharing are allocated to multiple MISO pricing zones. The remaining revenue requirement is assigned to the pricing zone where the transmission assets are located. Ameren Missouri uses a rate formula that is updated in June of each year and is based on the prior-year's cost data. The Ameren Missouri zonal rate is charged to wholesale customers in the AMMO pricing zone. However, this rate is not directly charged to Missouri retail customers because the MoPSC includes transmission-related costs in setting bundled retail rates in Missouri. Ameren Illinois and ATXI have received FERC approval to use company-specific, forward-looking rate formula templates in setting their transmission rates. These forward-looking rates are updated every January. Each year, after the costs are incurred, the January forecast rates are reconciled with the actual revenue requirement. In Illinois, the AMIL pricing zone rate is charged directly to wholesale customers and alternative retail electric suppliers that serve unbundled retail load. If Ameren Illinois retail customers do not choose an alternative retail electric supplier, the AMIL transmission rate, as well as other MISO related costs, is collected through the transmission services rider mechanism.

In our Missouri and Illinois retail natural gas utility jurisdictions, changes in natural gas costs are generally reflected in billings to natural gas customers through PGA clauses.

Ameren through Ameren Missouri is affected by changes in market prices for natural gas to the extent that it must purchase natural gas to run CTs. Ameren Missouri has structured various supply agreements to maintain access to multiple natural gas pools and supply basins, and to minimize the impact to its financial statements. Ameren Missouri’s exposure to changes in market prices of natural gas for generation is mitigated by its

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ability to recover increasing costs via the FAC. See Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk under Exhibit 99.3, Item 7A, of this Current Report on Form 8-K of this report for additional information.

See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information on the cost recovery mechanisms.

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EX-99.3

EXHIBIT 99.3

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Interest Rate Risk

We are exposed to market risk through changes in interest rates associated with:

• long-term and short-term variable-rate debt;

• fixed-rate debt;

• auction-rate long-term debt; and

• defined pension and postretirement benefit plans.

We manage our interest rate exposure by controlling the amount of debt instruments within our total capitalization portfolio and by monitoring the effects of market changes on interest rates. For defined pension and postretirement benefit plans, we control the duration and the portfolio mix of our plan assets.

At December 31, 2012, the estimated increase in our annual interest expense if interest rates were to increase by 1% on Ameren's variable-rate debt outstanding was $2 million. The corresponding decrease in net income would be $1 million, assuming an estimated tax rate of 37%.

Credit Risk

Credit risk represents the loss that would be recognized if counterparties should fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction. See Note 7 – Derivative Financial Instruments under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for information on the potential loss on counterparty exposure as of December 31, 2012.

Our rate-regulated revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables and executory contracts with market risk exposures. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our customer base. At December 31, 2012, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. Additionally, Ameren Illinois has risk associated with the purchase of receivables. The Illinois Public Utilities Act requires Ameren Illinois to establish electric utility consolidated billing and purchase of receivables services. At the option of an alternative retail electric supplier, Ameren Illinois is required to purchase the supplier's receivables relating to Ameren Illinois' delivery service customers who elected to receive power supply from the alternative retail electric supplier. When that option is selected, Ameren Illinois produces consolidated bills for the applicable retail customers reflecting charges for electric delivery service and purchased receivables. Beginning in June 2012, Ameren Illinois began purchasing trade receivables relating to the power supply of residential customers who use Marketing Company as their alternative retail electric supplier. As of December 31, 2012, Ameren Illinois' balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $9 million. The risk associated with Ameren Illinois' electric and natural gas trade receivables is also mitigated by a rate adjustment mechanism that allows Ameren Illinois to recover the difference between its actual bad debt expense under GAAP and the bad debt expense included in its base rates. Ameren Missouri and Ameren Illinois continue to monitor the impact of increasing rates on customer collections. Ameren Missouri and Ameren Illinois make adjustments to their respective allowance for doubtful accounts as deemed necessary to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.

Ameren may have credit exposure associated with off-system or wholesale purchase and sale activity. At December 31, 2012, Ameren’s credit exposure to trading counterparties, excluding coal suppliers, deemed below investment grade either through external or internal credit evaluations, was less than $1 million, net of collateral (2011 – $48 million). At December 31, 2012, Ameren's credit exposure to coal suppliers, deemed below investment grade either through external or internal credit evaluations, net of collateral, was $2 million (2011 – $33 million).

We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program. Monitoring involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each

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counterparty’s financial condition before we enter into sales, forwards, swaps, futures, or option contracts. At December 31, 2012, we estimate our credit exposure to MISO associated with the MISO Energy and Operating Reserves Market to be less than $1 million (2011 – $6 million).

Equity Price Risk

Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. Ameren’s goal is to ensure that sufficient funds are available to provide benefits at the time they are payable while also to maximizing total return on plan assets and minimizing expense volatility consistent with its tolerance for risk. Ameren delegates investment management to specialists. Where appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. Ameren regularly monitors manager performance and compliance with investment guidelines.

The expected return on plan assets 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 are 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 adjust 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.

In future years, the costs of such plans will be reflected in net income, OCI, or regulatory assets. Contributions to the plans could increase materially if we do not achieve pension and postretirement asset portfolio investment returns equal to or in excess of our 2013 assumed return on plan assets of 7.50% and 7.25%, respectively.

Ameren Missouri also maintains a trust fund, as required by the NRC and Missouri law, to fund certain costs of nuclear plant decommissioning. As of December 31, 2012, this fund was invested primarily in domestic equity securities (65%) and debt securities (35%). It totaled $408 million (2011 – $357 million). By maintaining a portfolio that includes long-term equity investments, Ameren Missouri seeks to maximize the returns to be used to fund nuclear decommissioning costs within acceptable parameters of risk. However, the equity securities included in the portfolio are exposed to price fluctuations in equity markets. The debt securities are exposed to changes in interest rates. Ameren Missouri actively monitors the portfolio by benchmarking the performance of its investments against certain indices and by maintaining and periodically reviewing established target allocation percentages of the assets of the trust to various investment options. Ameren Missouri’s exposure to equity price market risk is in large part mitigated because Ameren Missouri is currently allowed to recover its decommissioning costs, which would include unfavorable investment results, through electric

rates.

Additionally, Ameren has company-owned life insurance contracts that are used to support Ameren’s deferred compensation plans. These life insurance contracts include equity and debt investments that are exposed to price fluctuations in equity markets and to changes in interest rates.

Commodity Price Risk

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

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

If power prices were to decrease by 1% on unhedged economic generation for 2013 through 2016, Ameren earnings would decrease by less than $1 million, based on an 36% effective tax rate.

Ameren’s forward-hedging power programs include the use of derivative financial swap contracts. These swap contracts financially settle a fixed price against a floating price. The floating price is typically the realized, or settled, price at a liquid regional hub at some forward period of time. Ameren controls the use of derivative financial swap contracts with volumetric and correlation limits that are intended to mitigate any material adverse financial impact.

Ameren also uses its portfolio management and trading capabilities both to manage risk and to deploy capital to generate additional returns. Due to our physical presence in the market, we are able to identify and pursue opportunities, which can generate additional returns through portfolio management and trading activities. All of this activity is performed within a controlled risk management process. We establish value at risk and stop-loss limits that are intended to limit any material negative financial impacts.

We manage risks associated with changing prices of fuel for generation with techniques similar to those we use to manage risks associated with changing market prices for electricity.

Ameren Missouri has a FAC that allows Ameren Missouri to recover, through customer rates, 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. Ameren Missouri remains exposed to the

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remaining 5% of such changes. Ameren Illinois expects that purchased power procured through past IPA procurements will be in excess of requirements for the 2013 planning year due to significant switching by customers to alternative retail electric suppliers associated with municipal aggregation initiatives. The IPA has proposed and the ICC has approved that the excess purchased power will settle in the MISO market and be credited to customers taking power procured by Ameren Illinois through the IPA process. Ameren Illinois expects full recovery of its purchased power costs.

Ameren Missouri has entered into coal contracts with various suppliers to purchase coal to manage their exposure to fuel prices. The coal hedging strategy is intended to secure a reliable coal supply while reducing exposure to commodity price volatility. Additionally, the type of coal burned is part of Ameren Missouri's environmental compliance strategy. Ameren Missouri has a multiyear agreement to purchase ultra-low-sulfur coal through 2017 to comply with environmental regulations. The coal contract is with a single supplier. Disruptions of the deliveries of that ultra-low-sulfur coal from the supplier could compromise Ameren Missouri's ability to operate in compliance with emission standards. Other sources of ultra-low-sulfur coal are limited and the construction of pollution control equipment requires significant lead time to become operational. Should a temporary disruption of ultra-low-sulfur coal deliveries occur and its existing inventory of ultra-low-sulfur coal becomes fully depleted, and other sources of ultra-low-sulfur coal are not available, Ameren Missouri would use its existing emission allowances or purchase emission allowances in order to achieve compliance with environmental regulations.

Transportation costs for coal and natural gas can be a significant portion of fuel costs. Ameren Missouri typically hedges coal transportation forward to provide supply certainty and to mitigate transportation price volatility. Natural gas transportation expenses for Ameren’s gas distribution utility companies and for the gas-fired generation units of Ameren Missouri are regulated by FERC through approved tariffs governing the rates, terms, and conditions of transportation and storage services. Certain firm transportation and storage capacity agreements held by the Ameren Companies include rights to extend the term of contracts. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariff rates for our requirements.

In addition, coal transportation costs are sensitive to the price of diesel fuel as a result of rail freight fuel surcharges. We use forward fuel oil contracts (both for heating and crude oil) to mitigate this market price risk as changes in these products are highly correlated to changes in diesel markets. If diesel fuel costs were to increase or decrease by $0.25 a gallon, Ameren’s fuel expense could increase or decrease by $8 million annually. As of December 31, 2012, Ameren had a price cap for approximately 84% of expected fuel surcharges in 2013.

In the event of a significant change in coal prices, Ameren Missouri would probably take actions to further mitigate their exposure to this market risk. However, due to the uncertainty of

the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure or fuel sources.

With regard to exposure for commodity price risk for nuclear fuel, Ameren Missouri has fixed-priced, base-price-with-escalation, and market-priced agreements. It uses inventories to provide some price hedge to fulfill its Callaway energy center’s needs for uranium, conversion, and enrichment. There is no fuel reloading or planned maintenance outage scheduled for 2015. Ameren Missouri has price hedges for approximately 73% of its 2013 to 2017 nuclear fuel requirements.

Nuclear fuel market prices remain subject to an unpredictable supply-and-demand environment. Ameren Missouri has continued to follow a strategy of managing its inventory of nuclear fuel as an inherent price hedge. New long-term uranium contracts are almost exclusively market-price-related with an escalating price floor. New long-term enrichment contracts usually have a base-price-with-escalation price mechanism, and may also have either a market-price-related component or market-based price re benchmarking. Ameren Missouri expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected life of the Callaway energy center, at prices that cannot now be accurately predicted. Unlike the electricity and natural gas markets, nuclear fuel markets have somewhat limited financial instruments available for price hedging, so most hedging is done through inventories and forward contracts, if they are available.

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

Through the market allocation and auction process, Ameren Missouri has been granted FTRs associated with the MISO Energy and Operating Reserves Market. The FTRs are intended to mitigate electric transmission congestion charges related to the physical constraints of the transmission system. Depending on the congestion, FTRs could result in either charges or credits. Complex grid modeling tools are used to determine which FTRs to nominate in the FTR allocation process. There is a risk of incorrectly modeling the amount of FTRs needed, and there is the potential that the FTRs could be ineffective in mitigating transmission congestion charges.

With regard to Ameren Missouri’s and Ameren Illinois’ electric and natural gas distribution businesses, exposure to changing market prices is in large part mitigated by the fact that there are cost recovery mechanisms in place. These cost recovery mechanisms allow Ameren Missouri and Ameren Illinois to pass on to retail customers prudently incurred costs for fuel, purchased power, and gas supply. Ameren Illinois expects that purchased power procured through past IPA procurements will be in excess of requirements for the 2013 planning year due to

3

significant switching by customers to alternative retail electric suppliers associated with municipal aggregation initiatives.  The IPA has proposed and the ICC has approved that the excess purchased power will settle in the MISO market and act as a credit to customers taking power procured by Ameren Illinois through the IPA process.   Ameren Illinois expects full recovery of its purchased power costs.

Ameren Missouri’s and Ameren Illinois’ strategy is designed to reduce the effect of market fluctuations for their regulated customers. The effects of price volatility cannot be eliminated. However, procurement strategies involve risk management techniques and instruments similar to those outlined earlier, as well as the management of physical assets.

The following table presents, as of December 31, 2012, the percentages of the projected required supply of coal and coal transportation for Ameren Missouri's coal-fired energy centers, nuclear fuel for Ameren Missouri’s Callaway energy center, natural gas for our CTs and retail distribution, as appropriate, and purchased power needs of Ameren Illinois, which does not own generation, that are price-hedged over the period 2013 through 2017. The projected required supply of these commodities could be significantly affected by changes in our assumptions for matters such as customer demand for our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.

	2013		2014		2015 – 2017
Coal	100	%	100	%	94	%
Coal transportation	99		98		98
Nuclear fuel	100		99		49
Natural gas for generation	34		9		2
Natural gas for distribution(a)	82		34		9
Purchased power for Ameren Illinois(b)	100		100		50

(a) Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2013 represents January 2013 through March 2013. The year 2014 represents November 2013 through March 2014. This continues each successive year through March 2017.

(b) Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of demand.

If coal and coal transportation costs were to increase by 1% on any requirements not currently covered by fixed-price contracts for the five-year period 2013 through 2017, Ameren's fuel expense might increase by less than $1 million and net income might decrease by less than $1 million.

With regard to our exposure for commodity price risk for construction and maintenance activities, Ameren is exposed to changes in market prices for metal commodities and to labor availability.

See Note 15 – Commitments and Contingencies under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information.

Fair Value of Contracts

We use derivatives principally to manage the risk of changes in market prices for coal, natural gas, diesel, power, and uranium. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the year ended December 31, 2012. We use various methods to determine the fair value of our contracts. In accordance with authoritative accounting guidance for fair value with hierarchy levels, the sources we used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). See Note 8 – Fair Value Measurements under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for further information regarding the methods used to determine the fair value of these contracts.

	2012
Fair value of contracts at beginning of year, net	$	(89	)
Contracts realized or otherwise settled during the period	77
Changes in fair values attributable to changes in valuation technique and assumptions	—
Fair value of new contracts entered into during the period	16
Other changes in fair value	(205		)
Fair value of contracts outstanding at end of year, net	$	(201	)

4

The following table presents maturities of derivative contracts as of December 31, 2012, based on the hierarchy levels used to determine the fair value of the contracts:

Sources of Fair Value	Maturity Less Than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years			Maturity in Excess of 5 Years			Total Fair Value
Level 1	$	—		$	(4	)	$	—		$	—		$	(4	)
Level 2(a)	(60		)	(39		)	(1		)	—			(100		)
Level 3(b)	(8		)	(19		)	(20		)	(50		)	(97		)
Total	$	(68	)	$	(62	)	$	(21	)	$	(50	)	$	(201	)

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

(b) Principally power forward contract values based on a Black-Scholes model that includes information from external sources and our estimates. Level 3 also includes option contract values based on our estimates.

5

EX-99.4

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

1

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.

2

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.

3

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.

4

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.

5

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.

6

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

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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

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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

49

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,

50

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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EX-99.5

EXHIBIT 99.5

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Years Ended December 31, 2012, 2011 and 2010
(In millions)	2012			2011			2010
Operating revenues	$	—		$	—		$	—
Operating expenses	17			13			19
Operating loss	(17		)	(13		)	(19		)
Equity in earnings of subsidiaries	548			451			525
Interest income from affiliates	3			5			8
Miscellaneous expense	4			4			3
Interest charges	39			41			56
Income tax (benefit)	(27		)	(20		)	(28		)
Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations	518			418			483
Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations	(1,492		)	101			(344		)
Net income (Loss) Attributable to Ameren Corporation	$	(974	)	$	519		$	139
Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations	$	518		$	418		$	483
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	510			399			493
Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations	(1,492		)	101			(344		)
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Income Taxes	50			(14		)	(14		)
Comprehensive Income (Loss) from Discontinued Operations	(1,442		)	87			(358		)
Comprehensive Income (Loss) Attributable to Ameren Corporation	$	(932	)	$	486		$	135

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED BALANCE SHEET
(In millions)	December 31, 2012			December 31, 2011
Assets:
Cash and cash equivalents	$	23		$	3
Advances to money pool	316			340
Accounts and notes receivable - affiliates	31			57
Other current assets	49			—
Total current assets	419			400
Investments in subsidiaries - continuing operations	6,288			6,327
Investments in subsidiaries - discontinued operations	(326		)	1,155
Note receivable - affiliates	462			425
Other non-current assets	320			333
Total assets	$	7,163		$	8,640
Liabilities and Stockholders’ Equity:
Short-term debt	$	—		$	148
Accounts payable - affiliates	10			13
Other current liabilities	33			62
Total current liabilities	43			223
Long-term debt	424			424
Other deferred credits and liabilities	80			74
Total liabilities	547			721
Commitments and Contingencies
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 income (loss)	(8		)	(50		)
Total stockholders’ equity	6,616			7,919
Total liabilities and stockholders’ equity	$	7,163		$	8,640

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF CASH FLOWS For the Years Ended December 31, 2012, 2011 and 2010
(In millions)	2012			2011			2010
Net cash flows provided by operating activities	$	532		$	804		$	241
Cash flows from investing activities:
Money pool advances, net	24			(276		)	18
Notes receivable - affiliates, net	(20		)	358			242
Investments in subsidiaries	(2		)	(94		)	(13		)
Distributions from subsidiaries	21			3			1
Other	(5		)	(5		)	—
Net cash flows provided by (used in) investing activities	18			(14		)	248
Cash flows from financing activities:
Dividends on common stock	(382		)	(375		)	(368		)
Short-term debt and credit facility borrowings, net	(148		)	(481		)	(221		)
Issuances of common stock	—			65			80
Net cash flows used in financing activities	(530		)	(791		)	(509		)
Net change in cash and cash equivalents	$	20		$	(1	)	$	(20	)
Cash and cash equivalents at beginning of year	3			4			24
Cash and cash equivalents at the end of year	$	23		$	3		$	4
Cash dividends received from consolidated subsidiaries	$	610		$	730		$	368
Noncash financing activity – dividends on common stock	$	(7	)	$	—		$	—

AMEREN CORPORATION (parent company only)

NOTES TO CONDENSED FINANCIAL STATEMENTS

December 31, 2012

NOTE 1 - BASIS OF PRESENTATION

Ameren Corporation (parent company only) is a public utility holding company that conducts substantially all of its business operations through its subsidiaries. As specified in Note 5 - Long-term Debt and Equity Financings under Exhibit 99.4, Item 8, of this Current Report on Form 8-K, there are restrictions on Ameren Corporation’s (parent company only) ability to obtain funds from certain of its subsidiaries through dividends, loans or advances. In accordance with authoritative accounting guidance, Ameren Corporation (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included within the combined notes under Exhibit 99.4, Item 8, of this Current Report on Form 8-K.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. 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. 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 under Exhibit 99.4, Item 8, of this Current Report on Form 8-K 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. Therefore, Ameren has segregated New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers and presented them separately as discontinued operations for all periods presented on the Condensed Statement of Income (Loss) and Comprehensive Income (Loss) and Condensed Balance Sheet. See Note 16 - Divestiture Transactions and Discontinued Operations under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information regarding that presentation.

NOTE 2 - SHORT-TERM DEBT AND LIQUIDITY

See Note 4 - Short-term Debt and Liquidity under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for a description and details of short-term debt and liquidity needs of Ameren Corporation (parent company only).

NOTE 3 - LONG-TERM OBLIGATIONS

See Note 5 - Long-term Debt and Equity Financings under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for a description and details of long-term obligations of Ameren Corporation (parent company only).

NOTE 4 - COMMITMENTS AND CONTINGENCIES

See Note 14 - Related Party Transactions with New AER and Note 15 - Commitments and Contingencies under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for a description of all material contingencies and guarantees outstanding of Ameren Corporation (parent company only).

NOTE 5 - IMPAIRMENT

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 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 announcement that Ameren intends to exit the Merchant Generation segment before the end of the Merchant Generation's 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, in the fourth quarter of 2012, Ameren Corporation (parent company only) recorded a noncash pretax impairment charge of $1.88 billion to reduce its investment in certain of the Merchant Generation segment's coal and natural gas-fired energy centers to their estimated fair values. This charge was included within "Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations" (parent company only) in the Condensed Statement of Income (Loss) and Comprehensive Income (Loss) for the year ended December 31, 2012.

EX-99.6

EXHIBIT 99.6

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010
(in millions)
Column A	Column B		Column C				Column D		Column E
Description	Balance at Beginning of Period		(1) Charged to Costs and Expenses		(2) Charged to Other Accounts(a)		Deductions(b)		Balance at End of Period
Ameren:
Deducted from assets - allowance for doubtful accounts:
2012	$	20	$	30	$	2	$	35	$	17
2011	22		41		—		43		20
2010	24		32		—		34		22
Deferred tax valuation allowance:
2012	$	1	$	1	$	—	$	—	$	2
2011	1		—		—		—		1
2010	—		1		—		—		1

(a) Uncollectible account reserve associated with receivables purchased by Ameren Illinois from alternative retail electric suppliers as required by the Illinois Public Utility Act.

(b) Uncollectible accounts charged off, less recoveries.

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Commitments And Contingencies (Environmental Matters) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 state
Number of states participating in the cap-and-trade program	28
Percent of top performing facilities	12.00%
Estimated Capital Costs 2012 [Member]
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	$ 35
Estimated Capital Costs 2012 [Member] | Union Electric Company [Member]
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	105
Estimated Capital Costs 2012 [Member] | Ameren Energy Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	30
Estimated Capital Costs 2012 [Member] | Ameren Energy Resources Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	5
Newton Energy Center Scrubbers [Member] | Newton Energy Center Estimated Capital Costs 2013 to 2017 [Member] | Ameren Energy Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	20
Manufactured Gas Plant [Member]
Loss contingency range of possible loss, minimum	257.0
Loss contingency range of possible loss, maximum	339.0
Accrual for environmental loss contingencies	257.0	[1]
Manufactured Gas Plant [Member] | Ameren Illinois Company [Member]
Number of remediation sites	44
Former Coal Ash Landfill [Member] | Ameren Illinois Company [Member]
Loss contingency range of possible loss, minimum	0.5
Loss contingency range of possible loss, maximum	6.0
Accrual for environmental loss contingencies	0.5
Other Environmental [Member] | Ameren Illinois Company [Member]
Accrual for environmental loss contingencies	0.8
Former Coal Tar Distillery [Member] | Union Electric Company [Member]
Loss contingency range of possible loss, minimum	2.0
Loss contingency range of possible loss, maximum	5.0
Accrual for environmental loss contingencies	2.0
Sauget Area 2 [Member] | Union Electric Company [Member]
Loss contingency range of possible loss, minimum	0.3
Loss contingency range of possible loss, maximum	10.0
Accrual for environmental loss contingencies	0.3
Substation in St Charles, Missouri [Member] | Union Electric Company [Member]
Loss contingency range of possible loss, minimum	1.5
Loss contingency range of possible loss, maximum	2.3
Accrual for environmental loss contingencies	1.5
Minimum [Member]
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	395
Minimum [Member] | Union Electric Company [Member]
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	1,115
Minimum [Member] | Ameren Energy Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	350
Minimum [Member] | Ameren Energy Resources Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	45
Minimum [Member] | Estimated Capital Costs 2014 to 2017 [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	120
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	150
Minimum [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Union Electric Company [Member]
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	215
Minimum [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Ameren Energy Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	100
Minimum [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Ameren Energy Resources Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	20
Minimum [Member] | Estimated Capital Costs 2018 to 2022 [Member]
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	240
Minimum [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Union Electric Company [Member]
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	795
Minimum [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Ameren Energy Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	220
Minimum [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Ameren Energy Resources Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	20
Maximum [Member]
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	480
Maximum [Member] | Union Electric Company [Member]
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	1,340
Maximum [Member] | Ameren Energy Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	425
Maximum [Member] | Ameren Energy Resources Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	55
Maximum [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Union Electric Company [Member]
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	260
Maximum [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Ameren Energy Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	125
Maximum [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Ameren Energy Resources Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	25
Maximum [Member] | Estimated Capital Costs 2018 to 2022 [Member]
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	295
Maximum [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Union Electric Company [Member]
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations	975
Maximum [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Ameren Energy Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	270
Maximum [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Ameren Energy Resources Generating Company [Member]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	$ 25

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

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Nuclear Decommissioning Trust Fund Investments (Fair Value And The Gross Unrealized Losses Of The Available-For-Sale Securities Held In Nuclear Decommissioning Trust Fund) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Nuclear Decommissioning Trust Fund Investments [Line Items]
Less than 12 months, fair value	$ 24
Less than 12 months, gross unrealized losses	1
12 months or greater, fair value	14
12 months or greater, gross unrealized losses	10
Total, fair value	38
Total, gross unrealized losses	11
Debt Securities [Member]
Nuclear Decommissioning Trust Fund Investments [Line Items]
Less than 12 months, fair value	17
Total, fair value	17
Equity Securities [Member]
Nuclear Decommissioning Trust Fund Investments [Line Items]
Less than 12 months, fair value	7
Less than 12 months, gross unrealized losses	1
12 months or greater, fair value	14
12 months or greater, gross unrealized losses	10
Total, fair value	21
Total, gross unrealized losses	$ 11

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Derivative Financial Instruments (Derivatives That Qualify For Regulatory Deferral) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Derivative [Line Items]
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets	$ (112)	$ 51
Fuel Oils [Member]
Derivative [Line Items]
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets	(15)
Natural Gas [Member]
Derivative [Line Items]
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets	84	(26)
Power [Member]
Derivative [Line Items]
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets	(180)	80
Uranium [Member]
Derivative [Line Items]
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets	$ (1)	$ (3)

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Fair Value Measurements (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Counterparty default risk liability valuation adjustment related to derivative contracts	$ 7	$ 4

XML

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities Resulting From Temporary Differences) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Income Taxes [Line Items]
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	(251)	[1]	(217)	[1]
Total net accumulated deferred income tax liabilities	3,006		2,712
Current assets	$ 170		$ 98

[1] Includes deferred tax assets related to net operating loss and tax credit carryforwards detailed in the table below.

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Retirement Benefits (Target Allocation Of The Plans' Asset Categories) (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets	100.00%	100.00%
Pension Benefits [Member] | Cash and cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	0.00%
Maximum Target Allocation	5.00%
Percentage of Plan Assets	2.00%	2.00%
Pension Benefits [Member] | Total equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	50.00%
Maximum Target Allocation	60.00%
Percentage of Plan Assets	54.00%	51.00%
Pension Benefits [Member] | U.S. large capitalization [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	29.00%
Maximum Target Allocation	39.00%
Percentage of Plan Assets	34.00%	33.00%
Pension Benefits [Member] | U.S. small and mid-capitalization [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	2.00%
Maximum Target Allocation	12.00%
Percentage of Plan Assets	7.00%	7.00%
Pension Benefits [Member] | International and emerging markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	9.00%
Maximum Target Allocation	19.00%
Percentage of Plan Assets	13.00%	11.00%
Pension Benefits [Member] | Debt securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	35.00%
Maximum Target Allocation	45.00%
Percentage of Plan Assets	39.00%	42.00%
Pension Benefits [Member] | Real estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	0.00%
Maximum Target Allocation	9.00%
Percentage of Plan Assets	4.00%	4.00%
Pension Benefits [Member] | Private equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	0.00%
Maximum Target Allocation	4.00%
Percentage of Plan Assets	1.00%	1.00%
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets	100.00%	100.00%
Postretirement Benefits [Member] | Cash and cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	0.00%
Maximum Target Allocation	10.00%
Percentage of Plan Assets	4.00%	4.00%
Postretirement Benefits [Member] | Total equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	55.00%
Maximum Target Allocation	65.00%
Percentage of Plan Assets	62.00%	59.00%
Postretirement Benefits [Member] | U.S. large capitalization [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	33.00%
Maximum Target Allocation	43.00%
Percentage of Plan Assets	40.00%	38.00%
Postretirement Benefits [Member] | U.S. small and mid-capitalization [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	3.00%
Maximum Target Allocation	13.00%
Percentage of Plan Assets	8.00%	8.00%
Postretirement Benefits [Member] | International [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	10.00%
Maximum Target Allocation	20.00%
Percentage of Plan Assets	14.00%	13.00%
Postretirement Benefits [Member] | Debt securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Target Allocation	30.00%
Maximum Target Allocation	40.00%
Percentage of Plan Assets	34.00%	37.00%

XML

Retirement Benefits (Assumptions Used To Determine Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate at measurement date	4.50%	5.25%	5.75%
Expected return on plan assets	7.75%	8.00%	8.00%
Increase in future compensation	3.50%	3.50%	3.50%
Medical cost trend rate (initial)	0.00%	0.00%	0.00%
Medical cost trend rate (ultimate)	0.00%	0.00%	0.00%
Years to ultimate rate	0 years	0 years	0 years
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate at measurement date	4.50%	5.25%	5.75%
Expected return on plan assets	7.50%	7.75%	8.00%
Increase in future compensation	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	1 year	2 years	3 years

XML

Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

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

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

The market approach is used to measure the fair value of equity securities held in Ameren Missouri's nuclear decommissioning trust fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants and the trustee and investment managers. The S&P 500 index 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:

	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:

		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.

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.

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 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.

XML

Rate And Regulatory Matters (Narrative) (Details) (USD $)	1 Months Ended	12 Months Ended			1 Months Ended		1 Months Ended	12 Months Ended		12 Months Ended	60 Months Ended	0 Months Ended	3 Months Ended			3 Months Ended						3 Months Ended			1 Months Ended									1 Months Ended	12 Months Ended	1 Months Ended
	Nov. 30, 2012 design	Dec. 31, 2012 design	Dec. 31, 2011	Dec. 31, 2010	Jun. 30, 2008 FERC Relicensing [Member] Taum Sauk Energy Center [Member]	Dec. 31, 2012 Union Electric Company [Member] New Nuclear Energy Center COL [Member]	Apr. 30, 2011 Union Electric Company [Member] FAC Prudence Review [Member]	Dec. 31, 2012 Union Electric Company [Member] FAC Prudence Review [Member]	Feb. 29, 2012 Union Electric Company [Member] FAC Prudence Review [Member]	Dec. 31, 2012 Union Electric Company [Member] Entergy Refund [Member]	Dec. 31, 2005 Union Electric Company [Member] Pending FERC Case [Member] Power Purchase Agreement With Entergy Arkansas [Member]	Jul. 13, 2011 Union Electric Company [Member] Final Rate Order [Member] Electric Distribution [Member]	Dec. 31, 2012 Union Electric Company [Member] Final Rate Order [Member] Electric Distribution [Member]	May 31, 2010 Union Electric Company [Member] Final Rate Order [Member] Electric Distribution [Member] account	Jan. 31, 2009 Union Electric Company [Member] Final Rate Order [Member] Electric Distribution [Member]	Dec. 31, 2012 Union Electric Company [Member] Final Rate Order [Member] MEEIA [Member] Electric Distribution [Member]	Jul. 13, 2011 Union Electric Company [Member] Accounting Authority Order Request [Member] FAC Prudence Review [Member]	Dec. 31, 2012 Ameren Illinois Company [Member] customer	Dec. 31, 2012 Ameren Illinois Company [Member] Wholesale Distribution Rate Case [Member]	Jan. 31, 2011 Ameren Illinois Company [Member] Wholesale Distribution Rate Case [Member]	Dec. 31, 2012 Ameren Illinois Company [Member] IEIMA [Member]	Dec. 31, 2012 Ameren Illinois Company [Member] IEIMA [Member] Smart Grid [Member]	Mar. 31, 2013 Ameren Illinois Company [Member] Final Rate Order [Member] IEIMA [Member] Electric Distribution [Member]	Dec. 31, 2012 Ameren Illinois Company [Member] Final Rate Order [Member] IEIMA [Member] Electric Distribution [Member]	Jan. 31, 2013 Ameren Illinois Company [Member] Pending Rate Case [Member] Gas Distribution [Member]	Dec. 31, 2012 ATXI [Member] Potential Transmission Project Investments Through 2019 [Member] project	Dec. 31, 2012 Energy Infrastructure Investments and Other Nonfuel Costs [Member] Union Electric Company [Member] Final Rate Order [Member] Electric Distribution [Member]	Dec. 31, 2012 Pension and Other Post-Employment Benefit Costs [Member] Union Electric Company [Member] Final Rate Order [Member] Electric Distribution [Member]	Dec. 31, 2012 Amortization of Regulatory Asset [Member] Union Electric Company [Member] Final Rate Order [Member] Electric Distribution [Member]	Dec. 31, 2012 Net Base Fuel Costs [Member] Union Electric Company [Member] Final Rate Order [Member] Electric Distribution [Member]	Jul. 13, 2011 Net Base Fuel Costs [Member] Union Electric Company [Member] Final Rate Order [Member] Electric Distribution [Member]	Dec. 31, 2012 FAC [Member] Union Electric Company [Member]	Dec. 31, 2012 Maximum [Member] Union Electric Company [Member] New Nuclear Energy Center COL [Member]	Jan. 31, 2013 Maximum [Member] Ameren Illinois Company [Member] Pending Rate Case [Member] Gas Distribution [Member]	Dec. 31, 2012 Minimum [Member] Union Electric Company [Member] New Nuclear Energy Center COL [Member]	Jan. 31, 2013 Minimum [Member] Ameren Illinois Company [Member] Pending Rate Case [Member] Gas Distribution [Member]	Dec. 31, 2012 Pending FERC Case [Member] Ameren Illinois Company [Member] customer
Rate And Regulatory Matters [Line Items]
Cash and cash equivalents		$ 184,000,000	$ 248,000,000	$ 538,000,000										$ 16,000,000	$ 21,000,000
Disallowed capitalized costs associated with rebuilt Taum Sauk energy center												89,000,000
Authorized increase in revenue from utility service												173,000,000	260,000,000	230,000,000		80,000,000											96,000,000	10,000,000	6,000,000	84,000,000	52,000,000
Number of industrial customers who received a stay from Circuit Court														4
Utility revenue increase requested																				11,000,000					50,000,000
Loss Contingency, Settlement Agreement, Number of Wholesale Customers																																					4
Number of Wholesale Customers																		9																			5
Rate of return on common equity													9.80%												10.40%
Percent of capital structure composed of equity													52.30%												51.80%
Rate base													6,800,000,000												1,100,000,000
Percentage of Fixed non-volumetric customer charge																																		85.00%		80.00%
Investments in Power and Distribution Projects, Number of Projects																										3
Energy Efficiency program spending																147,000,000
Number of years approved																3 years						10 years
Percentage of Project Lost Revenue Included in Rates																90.00%
Remaining Percentage of Projected Lost Revenue																10.00%
Incentive Award if Energy Efficiency Goals Are Achieved																19,000,000
Achieved Percentage of Energy Efficiency Earnings For Incentive Award																100.00%
Incentive Award if Energy Efficiency Goals Are Achieved, Period																3 years
Minimum Percentage of Energy Efficiency Goal Achievement For Company To Be Eligible For Incentive Award																70.00%
Sharing level for FAC													95.00%																			95.00%
Revenue requirement transferred from net fuel cost to other nonfuel costs													33,000,000
Request to defer fixed costs not recovered from Noranda, amount																	36,000,000
Revenue Requirement																							779,000,000	764,000,000
Authorized Decrease In Revenue From Utility Service																							55,000,000	15,000,000
Regulatory liabilities		1,589,000,000	1,502,000,000																		55,000,000
Time required to complete FAC prudence reviews, in months								18 months
Contested Amounts Under FAC							18,000,000		26,000,000
Current regulatory liabilities		100,000,000	133,000,000																8,000,000
Proceeds from Legal Settlements										31,000,000
Purchased power		780,000,000	952,000,000	1,122,000,000						24,000,000	25,000,000
Department of Energy, Investing Funding Support, Number of Small Modular Reactor Designs		2
Department of Energy, Investing Funding Support, Period		5 years
Department of Energy, Investing Funding Support, Number of Small Modular Reactor Designs Awarded	1
Other Nonoperating Income		70,000,000	68,000,000	88,000,000						5,000,000
Reduction To Under-recovered Asset										2,000,000
Number Of Years COL is Valid For																																			40 years
Interest Expense		391,000,000	387,000,000	415,000,000			1,000,000
Capital investments						$ 69,000,000																$ 360,000,000				$ 1,300,000,000							$ 100,000,000		$ 80,000,000
Number of years for proposed relicensing application filed with FERC					40 years

XML

Consolidated Statement Of Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension and other postretirement activity, tax (benefit)	$ (6)	$ (14)	$ 6

XML

Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 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 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 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 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 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 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.

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Divestiture Transactions and Discontinued Operations (Narrative) (Details) (USD $) In Millions, unless otherwise specified							0 Months Ended	6 Months Ended		12 Months Ended			12 Months Ended			3 Months Ended	12 Months Ended		3 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010		Mar. 14, 2013 New Ameren Energy Resources Company, LLC [Member]	Jun. 30, 2013 New Ameren Energy Resources Company, LLC [Member]	Dec. 31, 2012 New Ameren Energy Resources Company, LLC [Member]	Dec. 31, 2012 Notes Payable, Other Payables [Member] New Ameren Energy Resources Company, LLC [Member]	Dec. 31, 2012 Illinois Power Holdings, LLC [Member]	Dec. 31, 2012 Elgin, Gibson City and Grand Tower Energy Centers [Member]	Dec. 31, 2012 Merchant Generation [Member]	Dec. 31, 2011 Merchant Generation [Member]	Dec. 31, 2010 Merchant Generation [Member]	Mar. 31, 2012 Merchant Generation [Member] Duck Creek Energy Center [Member]	Dec. 31, 2010 Medina Valley Energy Center [Member]	Dec. 31, 2010 SO2 Emission Allowances [Member] Merchant Generation [Member]	Jun. 30, 2013 Claimed Manufacturing Exemptions And Credits [Member] Merchant Generation [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Pension and other postretirement obligations assumed by counterparty									$ 40		$ 40
Defined benefit plan assets assumed by counterparty									15		15
Asset retirement obligation	375	[1]	369	[1],[2]	403	[1]			26
Converted instrument, period for conversion										24 months
Cash collateral for borrowed securities									27
Aggregate principal amount of senior notes							825
Transaction agreement, cash retained by counterparty							85
Transaction agreement, closing extension period							1 month
Obligation to provide credit support, period							24 months
Buyer's indemnification guarantee obligation							25
Buyer's indemnification guarantee obligation, period							24 months
Period for working capital adjustment							120 days
Transitional services to be provided to buyer, period							12 months
Transitional services to be provided to buyer at no charge, period							90 days
Transitional services to be provided to buyer at no charge, maximum amount							5
Transitional services to be provided to buyer, additional period							6 months
Impairment of assets to be disposed of								168					1,950	2	420	628	36	68
Disposal group, fair value												133
Discontinued operations deferred tax expense								97
Discontinued operations deferred tax benefit								69
Tax payment, settlement resolution																			$ 7

[1] 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.

[2] Balance included $5 million in "Other current liabilities" on the consolidated balance sheet as of December 31, 2011.

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

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.

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.

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 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 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.

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.

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 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. 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 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.

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Schedule I - Condensed Financial Information Of Parent Basis of Presentation Parent Company (Details) (Merchant Generation [Member], Parent Company [Member], USD $) In Millions, unless otherwise specified	0 Months Ended
	Mar. 14, 2013
Merchant Generation [Member] | Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Proceeds from Sales of Business, Affiliate and Productive Assets	$ 100

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Related Party Transactions (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended							12 Months Ended		0 Months Ended	3 Months Ended	0 Months Ended	1 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Ameren Energy Resources Generating Company [Member]	Dec. 31, 2012 Ameren Energy Marketing Company [Member]	Dec. 31, 2012 Midwest Independent Transmission System Operator, Inc [Member]	May 28, 2012 Ameren Energy Generating Company [Member]	Dec. 31, 2012 Ameren Energy Generating Company [Member] Ameren Transmission Company of Illinois [Member]	Dec. 31, 2012 Ameren Illinois Company [Member] Ameren Energy Marketing Company [Member]	Mar. 14, 2013 Elgin, Gibson City and Grand Tower Energy Centers [Member] Ameren Energy Generating Company [Member]	Sep. 30, 2013 Elgin, Gibson City and Grand Tower Energy Centers [Member] Ameren Energy Generating Company [Member]	Mar. 14, 2013 New Ameren Energy Resources Company, LLC [Member]	Apr. 30, 2010 Period Two [Member] Ameren Energy Marketing Company [Member]	Apr. 30, 2009 Period Two [Member] Ameren Energy Marketing Company [Member]	May 31, 2010 Period Two [Member] Ameren Illinois Company [Member] Ameren Energy Marketing Company [Member] MWh	May 31, 2009 Period Two [Member] Ameren Illinois Company [Member] Ameren Energy Marketing Company [Member] MWh	Apr. 30, 2010 Period Three [Member] Ameren Energy Marketing Company [Member]	Apr. 30, 2009 Period Three [Member] Ameren Energy Marketing Company [Member]	May 31, 2011 Period Three [Member] Ameren Illinois Company [Member] Ameren Energy Marketing Company [Member] MWh	May 31, 2010 Period Three [Member] Ameren Illinois Company [Member] Ameren Energy Marketing Company [Member] MWh	Apr. 30, 2012 Period Four [Member] Ameren Energy Marketing Company [Member]	Apr. 30, 2010 Period Four [Member] Ameren Energy Marketing Company [Member]	May 31, 2011 Period Four [Member] Ameren Illinois Company [Member] Ameren Energy Marketing Company [Member] MWh	Feb. 29, 2012 Period Six [Member] Ameren Illinois Company [Member] Ameren Energy Marketing Company [Member] MWh	Feb. 29, 2012 Period Seven [Member] Ameren Illinois Company [Member] Ameren Energy Marketing Company [Member] MWh	Apr. 30, 2012 Period Five [Member] Ameren Energy Marketing Company [Member]	Feb. 29, 2012 Period Five [Member] Ameren Illinois Company [Member] Ameren Energy Marketing Company [Member] MWh	May 31, 2011 Period Five [Member] Ameren Illinois Company [Member] Ameren Energy Marketing Company [Member] MWh	Apr. 30, 2009 Period One [Member] Ameren Energy Marketing Company [Member]	May 31, 2009 Period One [Member] Ameren Illinois Company [Member] Ameren Energy Marketing Company [Member] MWh	Dec. 31, 2012 Guarantee Type, Other [Member]
Related Party Transaction [Line Items]
Disposal Group, Including Discontinued Operation, Buyer's Indemnification Guarantee Obligation, Period												24 months
Business Acquisition Put Option Agreement Amount							$ 100
Put Option Premium							2.5
Energy Supply Agreements Amount													1	9			2	8			1	3				4			4
Long-term Contract for Purchase of Electric Power, Related Party Contract, Fixed Power															924,000	89,000			1,747,200	296,000			1,840,800	3,504,000	1,317,600		3,942,000	650,000		80,000
Long-term Contract for Purchase of Electric Power, Related Party Contract, Fixed Power, Rate															33	48			37	40			42	32	34		30	42		48
Intercompany Payables									5
Financing Receivable, Significant Purchases									35
Related Party Transaction, Purchases of Financing Receivable, Discount (less than $1 million)									1
Related Party Transaction, Proceeds from Sale of Assets								2
Related Party Transaction, Gain (Loss) on Sales of Assets								2
Related Party Transaction, Guarantees Outstanding	354			100	189	50																									15
Proceeds from Sale of Property, Plant, and Equipment		3	7							100	37
Related Party Transaction, Guarantees, Maximum Exposure					25	32
Letters of Credit Outstanding, Amount	9
Disposal Group, Including Discontinued Operation, Obligation to Provide Credit Support, Period												24 months
Disposal Group, Including Discontinued Operation, Buyer's Indemnification Guarantee Obligation												$ 25

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Other Income And Expenses (Other Income And Expenses) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2010
Other Nonoperating Income (Expense) [Line Items]
Interest and dividend income	$ 4	[1]	$ 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
Donations	24	[2]	8	19
Other	13		15	13
Total miscellaneous expense	37		23	32
Illinois Science and Energy Innovation Trust [Member] | Ameren Illinois Company [Member]
Other Nonoperating Income (Expense) [Line Items]
One-time Donation	7.5
Annual Donation	1
Customer Assistance Programs [Member] | Ameren Illinois Company [Member]
Other Nonoperating Income (Expense) [Line Items]
Annual Donation	$ 1

[1] 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.

[2] 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.

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Property And Plant, Net (Accrued Capital Expenditures) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment [Line Items]
Accrued capital expenditures	$ 103	$ 92	$ 70

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Nuclear Decommissioning Trust Fund Investments

12 Months Ended

Dec. 31, 2012

Investments, Debt and Equity Securities [Abstract]

NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS

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.

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.

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Callaway Energy Center (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 mill	Dec. 31, 2011	Dec. 31, 2010	Mar. 30, 2013
Loss Contingencies [Line Items]
Nwf Fee Number Of Mills	1
Settlement payment		$ 11		$ 5
Annual decommissioning costs included in costs of service	7	7	7
MoPSC requirement to file updated cost study and funding analysis for decommissioning Callaway energy center	3 years
Reduction To Depreciation And Amortization [Member]
Loss Contingencies [Line Items]
Settlement payment		2
Reduction To Other Operations And Maintenance [Member]
Loss Contingencies [Line Items]
Settlement payment		2
Reduction In Property And Plant [Member]
Loss Contingencies [Line Items]
Settlement payment	$ 1	$ 7
Nuclear Plant [Member]
Loss Contingencies [Line Items]
Useful life	40 years

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2012

Segment Reporting Information, Profit (Loss) [Abstract]

Schedule Of Segment Reporting Information, By Segment

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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Fair Value Measurements (Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level 3 In The Fair Value Hierarchy) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Fuel Oils [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ 3		$ 30
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	5		3
Change in unrealized gains (losses) related to assets/liabilities still held	(1)		(11)
Natural Gas [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(174)		(148)
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	0		(174)
Change in unrealized gains (losses) related to assets/liabilities still held	0		(78)
Power [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	81		19
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	(100)		81
Change in unrealized gains (losses) related to assets/liabilities still held	(175)	[1]	(25)
Derivative, term of contract	20 years
Uranium [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(1)		2
Included in regulatory assets/liabilities	(2)		(3)
Total realized and unrealized gains (losses)	(2)		(3)
Purchases			(1)
Settlements	1		1
Ending balance	(2)		(1)
Change in unrealized gains (losses) related to assets/liabilities still held	$ (1)		$ 0

[1] 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.

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Schedule I - Condensed Financial Information Of Parent (Balance Sheet) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
ASSETS
Cash and cash equivalents	$ 184	$ 248	$ 538
Accounts and notes receivable - affiliates	354	424
Other current assets	98	151
Total current assets	3,585	5,737
Other non-current assets	667	760
TOTAL ASSETS	22,219	23,723
LIABILITIES AND EQUITY
Short-term debt		148
Other current liabilities	168	195
Total current liabilities	2,660	3,373
Long-term debt	5,802	5,853
Other deferred credits and liabilities	642	424
Commitments and Contingencies
Retained earnings	1,006	2,369
Accumulated other comprehensive income (loss)	(8)	(50)
Total equity	6,767	8,068	7,884
TOTAL LIABILITIES AND EQUITY	22,219	23,723
Parent Company [Member]
ASSETS
Cash and cash equivalents	23	3	4	24
Advances to money pool	316	340
Accounts and notes receivable - affiliates	31	57
Other current assets	49
Total current assets	419	400
Investments in subsidiaries - continuing operations	6,288	6,327
Equity Method Investments - Discontinued Operations	(326)	1,155
Note receivable - affiliates	462	425
Other non-current assets	320	333
TOTAL ASSETS	7,163	8,640
LIABILITIES AND EQUITY
Short-term debt		148
Accounts payable - affiliates	10	13
Other current liabilities	33	62
Total current liabilities	43	223
Long-term debt	424	424
Other deferred credits and liabilities	80	74
Total liabilities	547	721
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 income (loss)	(8)	(50)
Total equity	6,616	7,919
TOTAL LIABILITIES AND EQUITY	$ 7,163	$ 8,640

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Short-Term Debt And Liquidity (Narrative) (Details) (USD $)									12 Months Ended		12 Months Ended
	Nov. 14, 2012 Illinois Credit Agreement 2012 [Member]	Dec. 31, 2012 Illinois Credit Agreement 2012 [Member] Maximum [Member]	Dec. 31, 2012 Illinois Credit Agreement 2012 [Member] Ameren Illinois Company [Member]	Nov. 14, 2012 Missouri Credit Agreement 2012 [Member]	Dec. 31, 2012 Missouri Credit Agreement 2012 [Member] Maximum [Member]	Dec. 31, 2012 Missouri Credit Agreement 2012 [Member] Union Electric Company [Member]	Dec. 31, 2012 Credit Agreements 2012 [Member]	Dec. 31, 2012 Unilateral Borrowing Agreement [Member] Ameren Illinois Company [Member]	Dec. 31, 2012 Multiyear Credit Facility [Member] lender	Dec. 31, 2012 Multiyear Credit Facility [Member] Maximum [Member]	Dec. 31, 2012 Commercial Paper [Member]	Dec. 31, 2011 Commercial Paper [Member]	Dec. 31, 2012 Utilities [Member]	Dec. 31, 2012 Non State Regulated Subsidiaries [Member]	Dec. 31, 2011 Non State Regulated Subsidiaries [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 1,100,000,000.0	$ 1,300,000,000.0	$ 800,000,000	$ 1,000,000,000	$ 1,200,000,000.0	$ 800,000,000	$ 2,090,000,000.00	$ 500,000,000	$ 2,100,000,000.0
Number of lenders									24
Line of credit facility, maximum borrowing capacity, per lender									125,000,000
Commercial paper outstanding												148,000,000
Average daily commercial paper borrowings outstanding											49,000,000	311,000,000
Weighted average interest rate											0.92%	0.87%
Peak short-term borrowings											229,000,000	435,000,000
Peak short-term borrowings interest rate											1.25%	1.46%
Debt-to-capital ratio									0.51	0.65
Minimum ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date									2.0 to 1.0
Current ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date									5.0 to 1.0
Covenant terms, default provisions, maximum indebtedness							$ 50,000,000
Short Term Debt, Weighted Average Interest Rate During Period													0.13%	0.61%	0.77%
Letters of credit portion of aggregate commitment									25.00%

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Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2012

Derivative Instrument Detail [Abstract]

Open Gross Derivative Volumes By Commodity Type

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.

Derivative Instruments Carrying Value

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.

Cumulative Pretax Net Gains (Losses) On All Derivative Instruments In OCI

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.

Maximum Exposure If Counterparties Fail To Perform On Contracts

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

Potential Loss On Counterparty Exposures

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:

	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

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 That Qualify For 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

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Segment Information

12 Months Ended

Dec. 31, 2012

Segment Reporting Information, Profit (Loss) [Abstract]

SEGMENT INFORMATION

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 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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Impairment and Other Charges

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

IMPAIRMENT AND OTHER CHARGES

MPAIRMENT 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.

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Retirement Benefits (Schedule Of Expected Payments From Qualified Trust And Company Funds) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Pension Benefits [Member] | Paid From Qualified Trust [Member]
Defined Benefit Plan Disclosure [Line Items]
2013	$ 229
2014	236
2015	239
2016	245
2017	248
2018 - 2022	1,279
Pension Benefits [Member] | Paid From Company Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
2013	3
2014	3
2015	3
2016	3
2017	3
2018 - 2022	13
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2013, Federal Subsidy	3
2014, Federal Subsidy	3
2015, Federal Subsidy	4
2016, Federal Subsidy	4
2017, Federal Subsidy	4
2018 - 2022, Federal Subsidy	19
Postretirement Benefits [Member] | Paid From Qualified Trust [Member]
Defined Benefit Plan Disclosure [Line Items]
2013	58
2014	60
2015	62
2016	65
2017	68
2018 - 2022	384
Postretirement Benefits [Member] | Paid From Company Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
2013	2
2014	2
2015	2
2016	2
2017	2
2018 - 2022	$ 11

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Divestiture Transactions and Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2012

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures

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.

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.

Schedule Of Coverage Ratios

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 Energy Generating Company [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Schedule Of Coverage Ratios

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.

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Property And Plant, Net (Tables)

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Schedule Of 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.

Accrued Capital Expenditures

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

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Nuclear Decommissioning Trust Fund Investments (Tables)

12 Months Ended

Dec. 31, 2012

Nuclear Decommissioning Trust Fund Investments [Line Items]

Fair Value Of Securities In Nuclear Decommissioning Trust Fund

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.

Schedule Of Unrealized Losses On Available-For-Sale Investments Included In 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.

Regulatory Asset [Member]

Nuclear Decommissioning Trust Fund Investments [Line Items]

Proceeds From Sale Of Investments In Nuclear Decommissioning Trust Fund And Gross Realized Gains And Losses

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

Fair Value Of Securities In Nuclear Decommissioning Trust Fund According To Their Contractual Maturities

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

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Selected Quarterly Information (Tables)

12 Months Ended

Dec. 31, 2012

Selected Quarterly Financial Information [Abstract]

Summary Of Selected Quarterly Information

	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.

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Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

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.

Consolidation

The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.

Public Utilities

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.

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.

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.

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

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.

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.

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 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.

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.

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.

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.

Cost Of Sales

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).

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.

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.

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 Interest

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.

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 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.

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Selected Quarterly Information (Summary Of Selected Quarterly Information) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended																12 Months Ended			3 Months Ended	6 Months Ended	9 Months Ended
	Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Mar. 31, 2012 Classification of Activity from Nuclear Decommissioning Trust Fund [Member]	Jun. 30, 2012 Classification of Activity from Nuclear Decommissioning Trust Fund [Member]	Sep. 30, 2012 Classification of Activity from Nuclear Decommissioning Trust Fund [Member]
Selected Quarterly Financial Information [Line Items]
Operating revenues	$ 1,258	[1]	$ 1,709	[1]	$ 1,402	[1]	$ 1,412	[1]	$ 1,296	[1]	$ 1,876	[1]	$ 1,458	[1]	$ 1,597	[1]	$ 5,781	$ 6,227	$ 6,269
Operating Income	111	[1],[2]	578	[1],[2]	344	[1],[2]	158	[1],[2]	91	[1],[2]	494	[1],[2]	270	[1],[2]	156	[1],[2]	1,191	1,011	1,125
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(1,155)	[1]	374	[1]	210	[1]	(403)	[1]	26	[1]	287	[1]	139	[1]	74	[1]	(974)	526	151
Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations	15	[1]	305	[1]	161	[1]	37	[1]	(1)	[1]	265	[1]	116	[1]	38	[1]	518	418	483
Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations	(1,171)	[1]	69	[1]	50	[1]	(440)	[1]	26	[1]	20	[1]	22	[1]	33	[1]	(1,492)	101	(344)
Net income (Loss) Attributable to Ameren Corporation	(1,156)	[1]	374	[1]	211	[1]	(403)	[1]	25	[1]	285	[1]	138	[1]	71	[1]	(974)	519	139
Earnings (Loss) per Common Share - Basic and Diluted - Continuing Operations	$ 0.06	[1]	$ 1.26	[1]	$ 0.66	[1]	$ 0.15	[1]	$ (0.01)	[1]	$ 1.10	[1]	$ 0.48	[1]	$ 0.16	[1]	$ 2.13	$ 1.73	$ 2.02
Earnings (Loss) per Common Share - Basic and Diluted - Discontinued Operations	$ (4.82)	[1]	$ 0.28	[1]	$ 0.21	[1]	$ (1.81)	[1]	$ 0.11	[1]	$ 0.08	[1]	$ 0.09	[1]	$ 0.13	[1]	$ (6.14)	$ 0.42	$ (1.44)
Earnings (Loss) per Common Share - Basic and Diluted	$ (4.76)	[1]	$ 1.54	[1]	$ 0.87	[1]	$ (1.66)	[1]	$ 0.10	[1]	$ 1.18	[1]	$ 0.57	[1]	$ 0.29	[1]	$ (4.01)	$ 2.15	$ 0.58
Impairment and other charges																		123	64
Quantifying Misstatement in Current Year Financial Statements, Amount																				$ 14	$ 26	$ 49

[1] 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.

[2] 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.

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Income Taxes (Reconciliation Of The Change In The Liability For Interest On Unrecognized Tax Benefits) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Contingency [Line Items]
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

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Long-Term Debt And Equity Financings (Schedule Of Outstanding Preferred Stock) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Long-Term Debt And Equity Financings [Line Items]
Preferred stock, par value	$ 0.01
Preferred stock, authorized	100,000,000
Preferred stock, shares outstanding	0
Preferred stock, issued	$ 142	[1]	$ 142	[1]
Preferred stock, voluntary liquidation	$ 106
Union Electric Company [Member]
Long-Term Debt And Equity Financings [Line Items]
Preferred stock, issued	80		80
Union Electric Company [Member] | Par Value $100 [Member]
Long-Term Debt And Equity Financings [Line Items]
Preferred stock, par value	$ 100
Preferred stock, authorized	25,000,000
Union Electric Company [Member] | Series $3.50 [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, per-dollar amount	$ 3.50
Preferred stock, shares outstanding	130,000
Preferred stock, redemption price per share	$ 110
Preferred stock, issued	13		13
Union Electric Company [Member] | Series $3.70 [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, per-dollar amount	$ 3.70
Preferred stock, shares outstanding	40,000
Preferred stock, redemption price per share	$ 105
Preferred stock, issued	4		4
Union Electric Company [Member] | Series $4.00 [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, per-dollar amount	$ 4.00
Preferred stock, shares outstanding	150,000
Preferred stock, redemption price per share	$ 106
Preferred stock, issued	15		15
Union Electric Company [Member] | Series $4.30 [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, per-dollar amount	$ 4.30
Preferred stock, shares outstanding	40,000
Preferred stock, redemption price per share	$ 105
Preferred stock, issued	4		4
Union Electric Company [Member] | Series $4.50 [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, per-dollar amount	$ 4.50
Preferred stock, shares outstanding	213,595
Preferred stock, redemption price per share	$ 110	[2]
Preferred stock, issued	21		21
Union Electric Company [Member] | Series $4.56 [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, per-dollar amount	$ 4.56
Preferred stock, shares outstanding	200,000
Preferred stock, redemption price per share	$ 102
Preferred stock, issued	20		20
Union Electric Company [Member] | Series $4.75 [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, per-dollar amount	$ 4.75
Preferred stock, shares outstanding	20,000
Preferred stock, redemption price per share	$ 102
Preferred stock, issued	2		2
Union Electric Company [Member] | Series $5.50 [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, per-dollar amount	$ 5.50
Preferred stock, shares outstanding	14,000
Preferred stock, redemption price per share	$ 110
Preferred stock, issued	1		1
Ameren Illinois Company [Member]
Long-Term Debt And Equity Financings [Line Items]
Preferred stock, issued	62		62
Ameren Illinois Company [Member] | Par Value $100 [Member]
Long-Term Debt And Equity Financings [Line Items]
Preferred stock, par value	$ 100
Preferred stock, authorized	2,000,000
Ameren Illinois Company [Member] | Series 4.00% [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, percentage	4.00%
Preferred stock, shares outstanding	144,275
Preferred stock, redemption price per share	$ 101
Preferred stock, issued	14		14
Ameren Illinois Company [Member] | Series 4.08% [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, percentage	4.08%
Preferred stock, shares outstanding	45,224
Preferred stock, redemption price per share	$ 103
Preferred stock, issued	5		5
Ameren Illinois Company [Member] | Series 4.20% [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, percentage	4.20%
Preferred stock, shares outstanding	23,655
Preferred stock, redemption price per share	$ 104
Preferred stock, issued	2		2
Ameren Illinois Company [Member] | Series 4.25% [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, percentage	4.25%
Preferred stock, shares outstanding	50,000
Preferred stock, redemption price per share	$ 102
Preferred stock, issued	5		5
Ameren Illinois Company [Member] | Series 4.26% [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, percentage	4.26%
Preferred stock, shares outstanding	16,621
Preferred stock, redemption price per share	$ 103
Preferred stock, issued	2		2
Ameren Illinois Company [Member] | Series 4.42% [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, percentage	4.42%
Preferred stock, shares outstanding	16,190
Preferred stock, redemption price per share	$ 103
Preferred stock, issued	2		2
Ameren Illinois Company [Member] | Series 4.70% [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, percentage	4.70%
Preferred stock, shares outstanding	18,429
Preferred stock, redemption price per share	$ 103
Preferred stock, issued	2		2
Ameren Illinois Company [Member] | Series 4.90% [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, percentage	4.90%
Preferred stock, shares outstanding	73,825
Preferred stock, redemption price per share	$ 102
Preferred stock, issued	7		7
Ameren Illinois Company [Member] | Series 4.92% [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, percentage	4.92%
Preferred stock, shares outstanding	49,289
Preferred stock, redemption price per share	$ 104
Preferred stock, issued	5		5
Ameren Illinois Company [Member] | Series 5.16% [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, percentage	5.16%
Preferred stock, shares outstanding	50,000
Preferred stock, redemption price per share	$ 102
Preferred stock, issued	5		5
Ameren Illinois Company [Member] | Series 6.625% [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, percentage	6.625%
Preferred stock, shares outstanding	124,274
Preferred stock, redemption price per share	$ 100
Preferred stock, issued	12		12
Ameren Illinois Company [Member] | Series 7.75% [Member]
Long-Term Debt And Equity Financings [Line Items]
Dividend rate on preferred shares, percentage	7.75%
Preferred stock, shares outstanding	4,542
Preferred stock, redemption price per share	$ 100
Preferred stock, issued	$ 1		$ 1

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

[2] In the event of voluntary liquidation, $105.50

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Income Taxes (Schedule Of Net Operating Loss Carryforwards And Tax Credit Carryforwards) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 200
Tax credit carryforwards	109
Change in valuation allowance	1
Federal [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	173	[1]
Tax credit carryforwards	86	[2]
Net operating loss carryforward, expiration period start	2028
Tax credit carryforward, expiration period start	Jan. 01, 2029
State [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	27	[3]
Tax credit carryforwards	25	[4]
Tax Credit Carryforward, Valuation Allowance	$ (2)	[5]
Net operating loss carryforward, expiration period start	2017
Tax credit carryforward, expiration period start	Jan. 01, 2013

[1] These will begin to expire in 2028.

[2] These will begin to expire in 2029.

[3] These will begin to expire in 2017.

[4] These will begin to expire in 2013.

[5] This balance increased by $1 million during 2012.

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Derivative Financial Instruments (Potential Loss On Counterparty Exposures) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	$ 15	$ 150
Affiliates [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts		1
Coal Producers [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts		35
Commodity Marketing Companies [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	1	85
Electric Utilities [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	1	3
Financial Companies [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	10	22
Municipalities/Cooperatives [Member]
Concentration Risk [Line Items]
Potential loss on counterparty exposures related to derivative contracts	$ 3	$ 4

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Impairment and Other Charges (Summary Of Goodwill And Other Asset Impairment Pretax Charges) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Impairment and Other Charges [Line Items]
Impairment charge on long-lived assets and related charges	$ 0	$ 123	$ 64
Total impairment charge		$ 123	$ 64

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Long-Term Debt And Equity Financings (Schedule Of Maturities Of Long-Term Debt) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Debt Instrument [Line Items]
2013	$ 355
2014	534
2015	120
2016	395
2017	681
Thereafter	4,082
Total	6,167
Parent Company [Member]
Debt Instrument [Line Items]
2013
2014	425
2015
2016
2017
Thereafter
Total	425
Unamortized discount and premium	1		1
Union Electric Company [Member]
Debt Instrument [Line Items]
2013	205	[1]
2014	109	[1]
2015	120	[1]
2016	266	[1]
2017	431	[1]
Thereafter	2,882	[1]
Total	4,013	[1]
Unamortized discount and premium	7		5
Ameren Illinois Company [Member]
Debt Instrument [Line Items]
2013	150	[1],[2]
2014		[1],[2]
2015		[1],[2]
2016	129	[1],[2]
2017	250	[1],[2]
Thereafter	1,200	[1],[2]
Total	1,729	[1],[2]
Unamortized discount and premium	6		8
Fair value adjustments	$ 4

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

[2] 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.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Schedule Of Effective Income Tax Rate Reconciliation

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.

Schedule Of Components Of Income Tax Expense (Benefit)

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

Schedule Of Deferred Tax Assets And Liabilities Resulting From Temporary Differences

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.

Schedule Of Net Operating Loss Carryforwards And Tax Credit Carryforwards

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.

Schedule Of Changes To Unrecognized Tax Benefits And Related Interest

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		$	—

Reconciliation Of Changes In Liability For Interest On Unrecognized Tax Benefits

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

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Derivative Financial Instruments (Derivative Instruments Carrying Value) (Details) (Not Designated As Hedging Instrument [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Derivative [Line Items]
Derivative assets	$ 29	[1]	$ 134	[1]
Derivative liabilities	230	[1]	223	[1]
Fuel Oils [Member] | Other current assets [Member]
Derivative [Line Items]
Derivative assets	8	[1]	17	[1]
Fuel Oils [Member] | Other assets [Member]
Derivative [Line Items]
Derivative assets	4	[1]	6	[1]
Fuel Oils [Member] | MTM derivative liabilities [Member]
Derivative [Line Items]
Derivative liabilities	2	[1]	1	[1]
Fuel Oils [Member] | Other deferred credits and liabilities [Member]
Derivative [Line Items]
Derivative liabilities	2	[1]		[1]
Natural Gas [Member] | Other current assets [Member]
Derivative [Line Items]
Derivative assets	1	[1]	3	[1]
Natural Gas [Member] | Other assets [Member]
Derivative [Line Items]
Derivative assets	1	[1]	1	[1]
Natural Gas [Member] | MTM derivative liabilities [Member]
Derivative [Line Items]
Derivative liabilities	64	[1]	103	[1]
Natural Gas [Member] | Other deferred credits and liabilities [Member]
Derivative [Line Items]
Derivative liabilities	45	[1]	92	[1]
Power [Member] | Other current assets [Member]
Derivative [Line Items]
Derivative assets	14	[1]	30	[1]
Power [Member] | Other assets [Member]
Derivative [Line Items]
Derivative assets	1	[1]	77	[1]
Power [Member] | MTM derivative liabilities [Member]
Derivative [Line Items]
Derivative liabilities	25	[1]	18	[1]
Power [Member] | Other deferred credits and liabilities [Member]
Derivative [Line Items]
Derivative liabilities	90	[1]	8	[1]
Uranium [Member] | MTM derivative liabilities [Member]
Derivative [Line Items]
Derivative liabilities	1	[1]		[1]
Uranium [Member] | Other deferred credits and liabilities [Member]
Derivative [Line Items]
Derivative liabilities	$ 1	[1]	$ 1	[1]

[1] Includes derivatives subject to regulatory deferral.

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Retirement Benefits (Fair Value Of Plan Assets Utilizing Fair Value Hierarchy) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Real estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Purchases, Sales, and Settlements	$ 3		$ 0
Fair value of plan assets	118		108		98
Private equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Purchases, Sales, and Settlements	(5)		(6)
Fair value of plan assets	19		23		28
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,127	[1]	2,814	[1]	2,664	[1]
Pension Benefits [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	452		389
Pension Benefits [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,611		2,362
Pension Benefits [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	137		131
Pension Benefits [Member] | Cash and cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	29		30
Pension Benefits [Member] | Cash and cash equivalents [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1
Pension Benefits [Member] | Cash and cash equivalents [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	28		30
Pension Benefits [Member] | U.S. large capitalization [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,090		973
Pension Benefits [Member] | U.S. large capitalization [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	83		72
Pension Benefits [Member] | U.S. large capitalization [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,007		901
Pension Benefits [Member] | U.S. small and mid-capitalization [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	235		202
Pension Benefits [Member] | U.S. small and mid-capitalization [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	235		202
Pension Benefits [Member] | U.S. small and mid-capitalization [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Pension Benefits [Member] | International and emerging markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	435		323
Pension Benefits [Member] | International and emerging markets [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	134		115
Pension Benefits [Member] | International and emerging markets [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	301		208
Pension Benefits [Member] | Corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	832		794
Pension Benefits [Member] | Corporate bonds [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	832		794
Pension Benefits [Member] | Municipal bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	176		176
Pension Benefits [Member] | Municipal bonds [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	176		176
Pension Benefits [Member] | U.S. treasury and agency securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	250		230
Pension Benefits [Member] | U.S. treasury and agency securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	250		230
Pension Benefits [Member] | Asset-backed securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18
Pension Benefits [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	17		23
Pension Benefits [Member] | Other [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	17		23
Pension Benefits [Member] | Real estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	118		108
Pension Benefits [Member] | Real estate [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	118		108
Pension Benefits [Member] | Private equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19		23
Pension Benefits [Member] | Private equity [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19		23
Pension Benefits [Member] | Derivative assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		1
Pension Benefits [Member] | Derivative assets [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		1
Pension Benefits [Member] | Derivative liabilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1)		(1)
Pension Benefits [Member] | Derivative liabilities [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1)		(1)
Pension Benefits [Member] | Medical benefit assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(102)	[2]	(91)	[2]
Pension Benefits [Member] | Net receivables [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	29	[3]	23	[3]
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	938	[1]	836	[1]	735	[1]
Postretirement Benefits [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	439		302
Postretirement Benefits [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	443		476
Postretirement Benefits [Member] | Cash and cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	83		66
Postretirement Benefits [Member] | Cash and cash equivalents [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	83		1
Postretirement Benefits [Member] | Cash and cash equivalents [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		65
Postretirement Benefits [Member] | U.S. large capitalization [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	333		284
Postretirement Benefits [Member] | U.S. large capitalization [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	245		206
Postretirement Benefits [Member] | U.S. large capitalization [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	88		78
Postretirement Benefits [Member] | U.S. small and mid-capitalization [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	66		57
Postretirement Benefits [Member] | U.S. small and mid-capitalization [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	66		57
Postretirement Benefits [Member] | International [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	114		94
Postretirement Benefits [Member] | International [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	45		38
Postretirement Benefits [Member] | International [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	69		56
Postretirement Benefits [Member] | Corporate bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	88		71
Postretirement Benefits [Member] | Corporate bonds [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	88		71
Postretirement Benefits [Member] | Municipal bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	91		80
Postretirement Benefits [Member] | Municipal bonds [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	91		80
Postretirement Benefits [Member] | U.S. treasury and agency securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	67		69
Postretirement Benefits [Member] | U.S. treasury and agency securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	67		69
Postretirement Benefits [Member] | Asset-backed securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18		23
Postretirement Benefits [Member] | Asset-backed securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			23
Postretirement Benefits [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	22		34
Postretirement Benefits [Member] | Other [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	22		34
Postretirement Benefits [Member] | Medical benefit assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	102	[2]	91	[2]
Postretirement Benefits [Member] | Net payables [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(46)	[4]	(33)	[4]
Includes Medical Benefit Component Under Section 401(h) And Excludes Receivables Related To Pending Security Sales [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,200		2,882
Excludes Medical Benefit Component Under Section 401(h) And Includes Receivables Related To Pending Security Sales [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,127		2,814
Excludes Medical Benefit Component Under Section 401(h) And Excludes Payables Related To Pending Security Sales [Member] | Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	882		778
Includes Medical Benefit Component Under Section401 H And Excludes Payables Related To Pending Security Sales [Member] | Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 938		$ 836

[1] Not applicable.

[2] 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.

[3] Receivables related to pending security sales, offset by payables related to pending security purchases.

[4] Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales.

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Retirement Benefits (Changes In The Fair Value Of Plan Assets Classified As Level 3) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Real estate [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	$ 108	$ 98
Actual Return on Plan Assets Related to Assets Still Held at the Reporting Date	7	10
Purchases, Sales and Settlements, net	3	0
Fair value of plan assets at end of year	118	108
Private equity [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	23	28
Actual Return on Plan Assets Related to Assets Still Held at the Reporting Date	(7)	(10)
Actual Return on Plan Assets Related to Assets Sold During the Period	8	11
Purchases, Sales and Settlements, net	(5)	(6)
Fair value of plan assets at end of year	$ 19	$ 23

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Commitments And Contingencies (Callaway Nuclear Energy Center) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012
Commitments and Contingencies [Line Items]
Insurance aggregate maximum coverage	$ 12,594,000,000	[1]
Insurance maximum coverage per incident	118,000,000
Threshold for which a retrospective assessment for a covered loss is necessary	375,000,000
Annual payment in the event of an incident at any licensed commercial reactor	17,500,000
Aggregate maximum assessment per incident under Price-Anderson liability provisions of Atomic Energy Act	118,000,000
Maximum annual payment to be paid in a calendar year per reactor incident under liability provisions of Atomic Energy Act	17,500,000
Amount of primary property liability coverage	500,000,000
Amount of coverage in excess of primary property liability coverage	2,250,000,000
Losses in excess of primary coverage	500,000,000
Amount of weekly indemnity coverage commencing eight weeks after power outage	4,500,000
Number of weeks of coverage after the first eight weeks of an outage	1 year
Amount of additional weekly indemnity coverage commencing after initial indemnity coverage	3,600,000
Number of additional weeks after initial indemnity coverage for power outage, minimum	5 years 11 months
Amount of weekly indemnity coverage thereafter not exceeding policy limit	490,000,000
Amount of secondary weekly indemnity coverage for prolonged nuclear plant outage in excess of primary indemnity coverage	900,000
Inflationary adjustment prescribed by most recent Price-Anderson Act renewal, in years	5 years
Aggregate nuclear power industry insurance policy limit for losses from terrorist attacks within twelve month period	3,240,000,000
Public Liability And Nuclear Worker Liability - American Nuclear Insurers [Member]
Commitments and Contingencies [Line Items]
Insurance aggregate maximum coverage	375,000,000
Insurance maximum coverage per incident	0
Public Liability And Nuclear Worker Liability - Pool Participation [Member]
Commitments and Contingencies [Line Items]
Insurance aggregate maximum coverage	12,219,000,000	[2]
Insurance maximum coverage per incident	118,000,000	[3]
Property Damage - Nuclear Electric Insurance Ltd [Member]
Commitments and Contingencies [Line Items]
Insurance aggregate maximum coverage	2,750,000,000	[4]
Insurance maximum coverage per incident	23,000,000	[5]
Replacement Power - Nuclear Electric Insurance Ltd [Member]
Commitments and Contingencies [Line Items]
Insurance aggregate maximum coverage	490,000,000	[6]
Insurance maximum coverage per incident	9,000,000	[5]
Replacement Power - Energy Risk Assurance Company [Member]
Commitments and Contingencies [Line Items]
Insurance aggregate maximum coverage	64,000,000	[7]
Insurance maximum coverage per incident	$ 0

[1] 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.

[2] Provided through mandatory participation in an industrywide retrospective premium assessment program.

[3] 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.

[4] 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.

[5] All Nuclear Electric Insurance Ltd. insured plants could be subject to assessments should losses exceed the accumulated funds from Nuclear Electric Insurance Ltd.

[6] 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.

[7] 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.

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Retirement Benefits (Summary Of Estimated Amortizable Amounts From Regulatory Assets and Accumulated OCI Into Net Periodic Benefit Cost) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	$ (1)
Net actuarial loss	97
Prior service cost (credit)	(2)
Net actuarial loss	5
Net periodic benefit cost	99
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	(4)
Net actuarial loss	19
Prior service cost (credit)	(1)
Net actuarial loss	0
Net periodic benefit cost	$ 14

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Divestiture Transactions and Discontinued Operations (Notes)

12 Months Ended

Dec. 31, 2012

Discontinued Operations and Disposal Groups [Abstract]

DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS

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 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 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

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.

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.

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

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 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.

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Consolidated Balance Sheet (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Statement of Financial Position [Abstract]
Accounts receivable - trade, allowance for doubtful accounts	$ 17	$ 20
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	400.0	400.0
Common stock, shares outstanding	242.6	242.6

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Income Taxes (Schedule Of Components Of Income Tax Expense (Benefit)) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Taxes [Line Items]
Current Federal taxes	$ 40	$ (6)	$ 3
Current State taxes	9	(2)	(1)
Deferred Federal taxes	205	206	247
Deferred State taxes	61	53	32
Deferred investment tax credits, amortization	(6)	(6)	(7)
Total income tax expense	$ 309	$ 245	$ 274

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Consolidated Statement Of Cash Flows (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Capitalized interest	$ 30	$ 30	$ 34

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Commitments And Contingencies (Asbestos-Related Litigation And Tax Exemptions And Credits) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 defendant
Asbestos-Related [Member]
Loss Contingencies [Line Items]
Number of defendants	79
Number of pending asbestos lawsuits as of the balance sheet date	121,000,000
Percent of allowed cash expenditures in excess of base rates to be recovered through charges assessed to customers	90.00%
Asbestos trust fund balance	$ 23
Percent of difference to be contributed to the asbestos trust fund if cash expenditures are less than amount included in base electric rates.	90.00%
Loss contingency range of possible loss, minimum	23.0
Minimum [Member] | Asbestos-Related [Member]
Loss Contingencies [Line Items]
Number of defendants	2
Maximum [Member] | Asbestos-Related [Member]
Loss Contingencies [Line Items]
Number of defendants	272
Parent Company [Member] | Asbestos-Related [Member]
Loss Contingencies [Line Items]
Number of pending asbestos lawsuits as of the balance sheet date	4,000,000
Union Electric Company [Member] | Asbestos-Related [Member]
Loss Contingencies [Line Items]
Number of pending asbestos lawsuits as of the balance sheet date	74,000,000
Ameren Illinois Company [Member] | Asbestos-Related [Member]
Loss Contingencies [Line Items]
Number of pending asbestos lawsuits as of the balance sheet date	96,000,000
Ameren Illinois Company [Member] | Collectibility of Taxes [Member]
Loss Contingencies [Line Items]
Number of customers affected	2,100
Loss contingency range of possible loss, minimum	2.0
Loss contingency range of possible loss, maximum	$ 4.0

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Rate And Regulatory Matters

12 Months Ended

Dec. 31, 2012

Public Utilities, General Disclosures [Abstract]

RATE AND REGULATORY MATTERS

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, 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 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. 

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 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.

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.

(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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Derivative Financial Instruments (Derivative Instruments With Credit Risk-Related Contingent Features) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Derivative Instrument Detail [Abstract]
Aggregate Fair Value of Derivative Liabilities	$ 226	[1]	$ 322	[1]
Cash Collateral Posted	61		104
Potential Aggregate Amount of Additional Collateral Required	$ 155	[2]	$ 211	[2]

[1] Prior to consideration of master trading and netting agreements and including NPNS and accrual contract exposures.

[2] 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.

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Schedule II - Valuation And Qualifying Accounts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Allowance For Doubtful Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	$ 20		$ 22		$ 24
Charged to Costs and Expenses	30		41		32
Charged to Other Accounts	2	[1]		[1]		[1]
Deductions	35	[2]	43	[2]	34	[2]
Balance at End of Period	17		20		22
Valuation Allowance of Deferred Tax Assets [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	1		1
Charged to Costs and Expenses	1				1
Charged to Other Accounts
Deductions
Balance at End of Period	$ 2		$ 1		$ 1

[1] Uncollectible account reserve associated with receivables purchased by Ameren Illinois from alternative retail electric suppliers as required by the Illinois Public Utility Act.

[2] Uncollectible accounts charged off, less recoveries.

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Consolidated Statement Of Stockholders' Equity (USD $) In Millions, unless otherwise specified		Total	Common Stock [Member]	Other Paid-In Capital [Member]	Retained Earnings [Member]	Derivative Financial Instruments [Member]	Deferred Retirement Benefit Costs [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]	Total Ameren Corporation Stockholders' Equity [Member]
Beginning of year at Dec. 31, 2009			$ 2	$ 5,412	$ 2,455	$ 10	$ (23)		$ 204
Beginning of year (shares) at Dec. 31, 2009		237.4
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued (value)				80
Shares issued (number of shares)		3.0
Stock-based compensation activity				14
Regulatory recovery of prior-period common stock issuance costs				14
Net income (loss) attributable to Ameren Corporation		139			139
Dividends					368
Other					(1)
Change in derivative financial instruments						(10)
Change in deferred retirement benefit costs		(10)					6
Net income attributable to noncontrolling interest holder									12
Dividends paid to noncontrolling interest holders									8
Redemptions of preferred stock									(52)
Other									(2)
Total stockholders' equity										7,730
Stockholders' equity, end of year at Dec. 31, 2010										7,730
End of year at Dec. 31, 2010		7,884	2	5,520	2,225		(17)	(17)	154
End of year (shares) at Dec. 31, 2010		240.4
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued (value)				65
Shares issued (number of shares)		2.2
Stock-based compensation activity				13
Regulatory recovery of prior-period common stock issuance costs
Net income (loss) attributable to Ameren Corporation		519			519
Dividends					375
Other
Change in derivative financial instruments						7
Change in deferred retirement benefit costs		19					(40)
Net income attributable to noncontrolling interest holder									7
Dividends paid to noncontrolling interest holders									6
Redemptions of preferred stock
Other									(6)
Total stockholders' equity		7,919								7,919
Stockholders' equity, end of year at Dec. 31, 2011		7,919								7,919
End of year at Dec. 31, 2011		8,068	2	5,598	2,369	7	(57)	(50)	149
End of year (shares) at Dec. 31, 2011		242.6
Beginning of year at Sep. 30, 2011
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) attributable to Ameren Corporation	[1]	25
Total stockholders' equity		7,919								7,919
Stockholders' equity, end of year at Dec. 31, 2011		7,919								7,919
End of year at Dec. 31, 2011		8,068	2	5,598	2,369	7	(57)	(50)	149
End of year (shares) at Dec. 31, 2011		242.6
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued (value)
Shares issued (number of shares)
Stock-based compensation activity				18
Regulatory recovery of prior-period common stock issuance costs
Net income (loss) attributable to Ameren Corporation		(974)			(974)
Dividends					389
Other
Change in derivative financial instruments						18
Change in deferred retirement benefit costs		8					24
Net income attributable to noncontrolling interest holder
Dividends paid to noncontrolling interest holders									6
Redemptions of preferred stock
Other									8
Total stockholders' equity		6,616								6,616
Stockholders' equity, end of year at Dec. 31, 2012		6,616								6,616
End of year at Dec. 31, 2012		6,767	2	5,616	1,006	25	(33)	(8)	151
End of year (shares) at Dec. 31, 2012		242.6
Beginning of year at Sep. 30, 2012
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) attributable to Ameren Corporation	[1]	(1,156)
Total stockholders' equity		6,616								6,616
Stockholders' equity, end of year at Dec. 31, 2012		6,616								6,616
End of year at Dec. 31, 2012		$ 6,767						$ (8)
End of year (shares) at Dec. 31, 2012		242.6

[1] 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.

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Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2012

Funded Status Of Benefit Plans And Amounts Included In Regulatory Assets And OCI

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.

Assumptions Used To Determine Benefit Obligations

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

Schedule Of Cash Contributions Made To Benefit Plans

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

Target Allocation Of The Plans' Asset Categories

The following table presents our target allocations for 2013 and our pension and postretirement plans’ asset categories as of December 31, 2012, and 2011.

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	%

Changes In The Fair Value Of Plan Assets Classified As Level 3

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

Components Of 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

Summary Of Estimated Amortizable Amounts From Regulatory Assets and Accumulated OCI Into Net Periodic Benefit Cost

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

Schedule Of Expected Payments From Qualified Trust And Company Funds

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:

	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

Assumptions Used To Determine Net Periodic Benefit Cost

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

Schedule Of Potential Changes In Key Assumptions

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		)

Pension Benefits [Member]

Target Allocation Of The Plans' Asset Categories

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.

Postretirement Benefits [Member]

Target Allocation Of The Plans' Asset Categories

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.

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

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Selected Quarterly Information

12 Months Ended

Dec. 31, 2012

Selected Quarterly Financial Information [Abstract]

SELECTED QUARTERLY INFORMATION

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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Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Schedule Of Materials And Supplies

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.

Schedule Of Asset Retirement Obligations

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.

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Derivative Financial Instruments (Maximum Exposure If Counterparties Fail To Perform On Contracts) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Concentration Risk [Line Items]
Maximum exposure to counterparties related to derivative contracts	$ 23	$ 156
Affiliates [Member]
Concentration Risk [Line Items]
Maximum exposure to counterparties related to derivative contracts		1
Coal Producers [Member]
Concentration Risk [Line Items]
Maximum exposure to counterparties related to derivative contracts		35
Commodity Marketing Companies [Member]
Concentration Risk [Line Items]
Maximum exposure to counterparties related to derivative contracts	2	85
Electric Utilities [Member]
Concentration Risk [Line Items]
Maximum exposure to counterparties related to derivative contracts	3	4
Financial Companies [Member]
Concentration Risk [Line Items]
Maximum exposure to counterparties related to derivative contracts	15	27
Municipalities/Cooperatives [Member]
Concentration Risk [Line Items]
Maximum exposure to counterparties related to derivative contracts	$ 3	$ 4

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Retirement Benefits (Schedule Of Matching Contributions) (Details) (401 (K) [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
401 (K) [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 28	$ 28	$ 27

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Divestiture Transactions and Discontinued Operations (Components of Assets and Liabilities on Consolidated Balance Sheet) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Current assets of discontinued operations
Cash and cash equivalents	$ 25		$ 7		$ 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)	19	[1]	(31)	[1]
Noncontrolling Interest	$ 8	[2]	$ 7	[2]
Electric Energy, Inc [Member]
Current liabilities of discontinued operations
Percentage of EEI not owned by Ameren	20.00%

[1] 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.

[2] 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.

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Other Income And Expenses (Tables)

12 Months Ended

Dec. 31, 2012

Other Nonoperating Income (Expense) [Abstract]

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.

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Derivative Financial Instruments (Cumulative Amount Of Pretax Net Gains (Losses) On All Derivative Instruments In OCI) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Derivative [Line Items]
Current gains deferred as regulatory liabilities	$ 100		$ 133
Current losses deferred as regulatory assets	247		215
Power [Member]
Derivative [Line Items]
Current gains deferred as regulatory liabilities	14
Current losses deferred as regulatory assets	24
Fuel Oils [Member]
Derivative [Line Items]
Current gains deferred as regulatory liabilities	4
Current losses deferred as regulatory assets	1
Natural Gas [Member]
Derivative [Line Items]
Current gains deferred as regulatory liabilities	1
Current losses deferred as regulatory assets	64
Uranium [Member]
Derivative [Line Items]
Current losses deferred as regulatory assets	1
Regulatory Liabilities Or Assets [Member] | Power [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(99)	[1]	81	[1]
Regulatory Liabilities Or Assets [Member] | Fuel Oils [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	4	[2]	19	[2]
Regulatory Liabilities Or Assets [Member] | Natural Gas [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	(107)	[3]	(191)	[3]
Regulatory Liabilities Or Assets [Member] | Uranium [Member]
Derivative [Line Items]
Cumulative deferred pretax gains (losses)	$ (2)	[4]	$ (1)	[4]

[1] 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.

[2] 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.

[3] 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.

[4] 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.

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Retirement Benefits (Components Of Net Periodic Benefit Cost) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 81	[1]	$ 73	[1]	$ 65
Interest cost	166	[1]	175	[1]	181
Expected return on plan assets	(208)		(211)		(208)
Transition obligation	0		0		0
Prior service cost	(3)		(1)		6
Actuarial loss	75		41		18
Net periodic benefit cost	111		77		62
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	22	[1]	20	[1]	18
Interest cost	47	[1]	54	[1]	58
Expected return on plan assets	(56)		(50)		(51)
Transition obligation	2		2		2
Prior service cost	(6)		(6)		(6)
Actuarial loss	5		3		0
Net periodic benefit cost	$ 14		$ 23		$ 21

[1] Not applicable.

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Property And Plant, Net (Schedule Of Property And Plant, Net) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 equipment agreement		Dec. 31, 2011 equipment agreement
Property, Plant and Equipment [Line Items]
Property and plant, at original cost	$ 22,796	[1]	$ 21,849	[1]
Accumulated depreciation and amortization	8,346	[1]	7,868	[1]
Property and plant, before construction work in progress	14,450	[1]	13,981	[1]
Property, Plant and Equipment, Net	15,348	[1]	14,848	[1]
Number of combustion turbine electric generation equipment under capital lease agreements	2		2
Number of capital lease agreements	2		2
Capital lease agreements, gross asset value	228		229
Total accumulated depreciation, capital lease agreements	52		52
Held-to-maturity Securities	304		309
Electric [Member]
Property, Plant and Equipment [Line Items]
Property and plant, at original cost	20,942	[1]	20,098	[1]
Gas [Member]
Property, Plant and Equipment [Line Items]
Property and plant, at original cost	1,854	[1]	1,751	[1]
Nuclear Fuel [Member]
Property, Plant and Equipment [Line Items]
Construction work in progress	317	[1]	255	[1]
Other Energy [Member]
Property, Plant and Equipment [Line Items]
Construction work in progress	$ 581	[1]	$ 612	[1]

[1] 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.

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Summary Of Significant Accounting Policies (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended						0 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Ameren Illinois Company [Member] sqmi people	Dec. 31, 2012 Union Electric Company [Member] sqmi people	Dec. 31, 2012 Electric Energy Inc [Member]	Mar. 14, 2013 Ameren Energy Generating Company [Member]	Dec. 31, 2011 Shutdown Of Meredosia And Hutsonville Energy Centers [Member]	Dec. 31, 2012 Voluntary Separation Offer [Member]	Dec. 31, 2011 SO2 Emission Allowances [Member]	Dec. 31, 2012 Minimum [Member]	Dec. 31, 2011 Minimum [Member]	Dec. 31, 2010 Minimum [Member]	Dec. 31, 2012 Maximum [Member]	Dec. 31, 2011 Maximum [Member]	Dec. 31, 2010 Maximum [Member]	Dec. 31, 2012 Power [Member] Ameren Illinois Company [Member] customer	Dec. 31, 2012 Power [Member] Union Electric Company [Member] customer	Dec. 31, 2012 Natural Gas [Member] Ameren Illinois Company [Member] customer	Dec. 31, 2012 Natural Gas [Member] Union Electric Company [Member] customer	Dec. 31, 2012 FAC [Member] Union Electric Company [Member]
Accounting Policies [Line Items]
Public utilities, Area serviced				40,000	24,000
Public utilities, Estimated population of service territory				3,100,000	2,800,000
Public uitilities, Number of customers																	1,200,000	1,200,000	806,000	127,000
Ownership percentage by parent						80.00%
Initial payment received		$ 3	$ 7				$ 100
Percent of average depreciable cost											3.00%	3.00%	3.00%	4.00%	4.00%	4.00%
Allowance for funds used during construction, rate											8.00%	8.00%	8.00%	9.00%	9.00%	9.00%
Book value	14	7
Amortization expense	4	3	13
Pretax impairment charge										1
Sharing level for FAC																					95.00%
Excise tax expense	193	194	189
Tax grants received related to renewable energy properties	18				18
Percentage of EEI not owned by Ameren						20.00%
Number of employee positions eliminated									340
Severance costs								$ 4	$ 28

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Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Schedule Of Insurance Coverage At 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.

Schedule Of Lease Obligations

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.

Schedule Of Estimated Purchased Commitments

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.

Schedule Of Estimated Capital Costs To Comply With Existing And Known Emissions Related Regulations

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.

	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.

Schedule Of Estimated Obligations For Manufactured Gas Plant Remediation

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.

Schedule Of Asbestos-Related Litigation Pending Lawsuits

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.

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Consolidated Statement Of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Other Comprehensive Income (Loss), Net of Taxes	$ 524	$ 424	$ 492
Pension and other postretirement activity, net of income taxes (benefit)	(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 Discontinued Operations Attributable to Noncontrolling Interest	2	(5)	1
Comprehensive Income (Loss) from Discontinued Operations Attributed to Ameren Corporation	(1,442)	87	(358)
Comprehensive Income (Loss) from Continuing Operations	$ (932)	$ 486	$ 135

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Long-Term Debt And Equity Financings

12 Months Ended

Dec. 31, 2012

Long-Term Debt And Equity Financings [Abstract]

LONG-TERM DEBT AND EQUITY FINANCINGS

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

	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.

(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.

(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.

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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Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Current Assets:
Cash and cash equivalents	$ 184		$ 248
Accounts receivable - trade (less allowance for doubtful accounts)	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
Current assets of discontinued operations	1,600		3,718
Total current assets	3,585		5,737
Property, Plant and Equipment, Net	15,348	[1]	14,848	[1]
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
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
Current liabilities of discontinued operations	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)
Stockholders' Equity:
Common stock	2		2
Other paid-in capital	5,616		5,598
Retained earnings	1,006		2,369
Accumulated other comprehensive income (loss)	(8)		(50)
Total stockholders' equity	6,616		7,919
Noncontrolling Interests	151		149
Total equity	6,767		8,068
TOTAL LIABILITIES AND EQUITY	$ 22,219		$ 23,723

[1] 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.

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Short-Term Debt And Liquidity (Schedule Of Maximum Aggregate Amount Available On Credit Agreements) (Details) (USD $)	Nov. 14, 2012 Illinois Credit Agreement 2012 [Member]	Dec. 31, 2012 Illinois Credit Agreement 2012 [Member] Parent Company [Member]	Dec. 31, 2012 Illinois Credit Agreement 2012 [Member] Ameren Illinois Company [Member]	Nov. 14, 2012 Missouri Credit Agreement 2012 [Member]	Dec. 31, 2012 Missouri Credit Agreement 2012 [Member] Parent Company [Member]	Dec. 31, 2012 Missouri Credit Agreement 2012 [Member] Union Electric Company [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 1,100,000,000.0	$ 300,000,000	$ 800,000,000	$ 1,000,000,000	$ 500,000,000	$ 800,000,000

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Consolidated Statement Of Income (Loss) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 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 (in dollars per share)	$ 2.13	$ 1.73	$ 2.02
Discontinued Operations (in dollars per share)	$ (6.14)	$ 0.42	$ (1.44)
Net Income (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

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Summary Of Significant Accounting Policies (Schedule Of Material And Supplies) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Accounting Policies [Abstract]
Fuel	$ 198	[1]	$ 150	[1]
Gas stored underground	131		171
Other materials and supplies	241		229
Total materials and supplies	$ 570		$ 550

[1] Consists of coal, oil, paint, propane, and tire chips.

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Fair Value Measurements (Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	$ 406	[1]	$ 358	[2]
Assets	435		492
Excluded receivables, payables, and accrued income, net	2		(1)
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	265	[1]	237	[2]
Assets	269		259
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	141	[1]	121	[2]
Assets	144		122
Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Assets	22		111
Fuel Oils [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	8	[3]
Cash And Cash Equivalents [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	3	[2]
Cash And Cash Equivalents [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	3	[2]
Cash And Cash Equivalents [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Cash And Cash Equivalents [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Commodity Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	29	[3]	134	[3]
Derivative liabilities	230	[3]	223	[3]
Commodity Contracts [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	4	[3]	22	[3]
Derivative liabilities	8	[3]	20	[3]
Commodity Contracts [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	3	[3]	1	[3]
Derivative liabilities	103	[3]	1	[3]
Commodity Contracts [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	22	[3]	111	[3]
Derivative liabilities	119	[3]	202	[3]
Commodity Contracts [Member] | Fuel Oils [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	12	[3]	23	[3]
Derivative liabilities	4	[3]	1	[3]
Commodity Contracts [Member] | Fuel Oils [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	4	[3]	20	[3]
Derivative liabilities	1	[3]	1	[3]
Commodity Contracts [Member] | Fuel Oils [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		[3]		[3]
Derivative liabilities		[3]		[3]
Commodity Contracts [Member] | Fuel Oils [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	8	[3]	3	[3]
Derivative liabilities	3	[3]		[3]
Commodity Contracts [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	2	[3]	4	[3]
Derivative liabilities	109	[3]	195	[3]
Commodity Contracts [Member] | Natural Gas [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		[3]	2	[3]
Derivative liabilities	7	[3]	19	[3]
Commodity Contracts [Member] | Natural Gas [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	2	[3]		[3]
Derivative liabilities	102	[3]		[3]
Commodity Contracts [Member] | Natural Gas [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		[3]	2	[3]
Derivative liabilities		[3]	176	[3]
Commodity Contracts [Member] | Power [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	15	[3]	107	[3]
Derivative liabilities	115	[3]	26	[3]
Commodity Contracts [Member] | Power [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets		[3]		[3]
Derivative liabilities		[3]		[3]
Commodity Contracts [Member] | Power [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	1	[3]	1	[3]
Derivative liabilities	1	[3]	1	[3]
Commodity Contracts [Member] | Power [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative assets	14	[3]	106	[3]
Derivative liabilities	114	[3]	25	[3]
Commodity Contracts [Member] | Uranium [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	2	[3]	1	[3]
Commodity Contracts [Member] | Uranium [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities		[3]		[3]
Commodity Contracts [Member] | Uranium [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities		[3]		[3]
Commodity Contracts [Member] | Uranium [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative liabilities	2	[3]	1	[3]
Equity Securities [Member] | U.S. Large Capitalization [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	264	[1]	234	[2]
Equity Securities [Member] | U.S. Large Capitalization [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	264	[1]	234	[2]
Equity Securities [Member] | U.S. Large Capitalization [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Equity Securities [Member] | U.S. Large Capitalization [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Debt Securities [Member] | Corporate Bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	47	[1]	44	[2]
Debt Securities [Member] | Corporate Bonds [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Debt Securities [Member] | Corporate Bonds [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	47	[1]	44	[2]
Debt Securities [Member] | Corporate Bonds [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Debt Securities [Member] | Municipal Bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	1	[2]
Debt Securities [Member] | Municipal Bonds [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Debt Securities [Member] | Municipal Bonds [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	1	[2]
Debt Securities [Member] | Municipal Bonds [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Debt Securities [Member] | U.S. treasury and agency securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	81	[1]	65	[2]
Debt Securities [Member] | U.S. treasury and agency securities [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Debt Securities [Member] | U.S. treasury and agency securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	81	[1]	65	[2]
Debt Securities [Member] | U.S. treasury and agency securities [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Debt Securities [Member] | Asset-Backed Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	11	[1]	10	[2]
Debt Securities [Member] | Asset-Backed Securities [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Debt Securities [Member] | Asset-Backed Securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	11	[1]	10	[2]
Debt Securities [Member] | Asset-Backed Securities [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Debt Securities [Member] | Other debt securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	1	[2]
Debt Securities [Member] | Other debt securities [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]
Debt Securities [Member] | Other debt securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund	1	[1]	1	[2]
Debt Securities [Member] | Other debt securities [Member] | Significant Other Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Nuclear Decommissioning Trust Fund		[1]		[2]

[1] Balance excludes $2 million of receivables, payables, and accrued income, net.

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

[3] The derivative asset and liability balances are presented net of counterparty credit considerations.

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Divestiture Transactions and Discontinued Operations (Debt Ratios) (Details) (Ameren Energy Generating Company [Member])	12 Months Ended
	Dec. 31, 2012
Minimum Required Ratio [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest coverage ratio, restricted payment	1.75	[1]
Interest coverage ratio, additional indebtedness	2.5	[2]
Debt-to-capital ratio, additional indebtedness	0.60	[2]
Actual Ratio [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest coverage ratio, restricted payment	2.6	[1]
Interest coverage ratio, additional indebtedness	2.6	[2]
Debt-to-capital ratio, additional indebtedness	0.44	[2]

[1] 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.

[2] 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.

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Derivative Financial Instruments (Other Derivatives) (Details) (Not Designated As Hedging Instrument [Member], Natural Gas (Generation) [Member], Operating Expenses-Fuel [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Not Designated As Hedging Instrument [Member] | Natural Gas (Generation) [Member] | Operating Expenses-Fuel [Member]
Derivative [Line Items]
Gain (Loss) Recognized in Income		$ (1)

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Schedule I - Condensed Financial Information Of Parent

12 Months Ended

Dec. 31, 2012

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Financial Information Of Parent

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Years Ended December 31, 2012, 2011 and 2010
(In millions)	2012			2011			2010
Operating revenues	$	—		$	—		$	—
Impairment and other charges	—			—			—
Operating expenses	17			13			19
Operating loss	(17		)	(13		)	(19		)
Equity in earnings of subsidiaries	548			451			525
Interest income from affiliates	3			5			8
Miscellaneous expense	4			4			3
Interest charges	39			41			56
Income tax (benefit)	(27		)	(20		)	(28		)
Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations	518			418			483
Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations	(1,492		)	101			(344		)
Net income (Loss) Attributable to Ameren Corporation	$	(974	)	$	519		$	139
Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations	$	518		$	418		$	483
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	$	510		$	399		$	493
Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations	$	(1,492	)	$	101		$	(344	)
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Income Taxes	$	50		$	(14	)	$	(14	)
Comprehensive Income (Loss) from Discontinued Operations	$	(1,442	)	$	87		$	(358	)
Comprehensive Income (Loss) Attributable to Ameren Corporation	$	(932	)	$	486		$	135

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED BALANCE SHEET
(In millions)	December 31, 2012			December 31, 2011
Assets:
Cash and cash equivalents	$	23		$	3
Advances to money pool	316			340
Accounts and notes receivable - affiliates	31			57
Other current assets	49			—
Total current assets	419			400
Investments in subsidiaries - continuing operations	6,288			6,327
Investments in subsidiaries - discontinued operations	(326		)	1,155
Note receivable - affiliates	462			425
Other non-current assets	320			333
Total assets	$	7,163		$	8,640
Liabilities and Stockholders’ Equity:
Short-term debt	$	—		$	148
Accounts payable - affiliates	10			13
Other current liabilities	33			62
Total current liabilities	43			223
Long-term debt	424			424
Other deferred credits and liabilities	80			74
Total liabilities	547			721
Commitments and Contingencies
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 income (loss)	(8		)	(50		)
Total stockholders’ equity	6,616			7,919
Total liabilities and stockholders’ equity	$	7,163		$	8,640

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF CASH FLOWS For the Years Ended December 31, 2012, 2011 and 2010
(In millions)	2012			2011			2010
Net cash flows provided by operating activities	$	532		$	804		$	241
Cash flows from investing activities:
Money pool advances, net	24			(276		)	18
Notes receivable - affiliates, net	(20		)	358			242
Investments in subsidiaries	(2		)	(94		)	(13		)
Distributions from subsidiaries	21			3			1
Other	(5		)	(5		)	—
Net cash flows provided by (used in) investing activities	18			(14		)	248
Cash flows from financing activities:
Dividends on common stock	(382		)	(375		)	(368		)
Short-term debt and credit facility borrowings, net	(148		)	(481		)	(221		)
Issuances of common stock	—			65			80
Net cash flows used in financing activities	(530		)	(791		)	(509		)
Net change in cash and cash equivalents	$	20		$	(1	)	$	(20	)
Cash and cash equivalents at beginning of year	3			4			24
Cash and cash equivalents at the end of year	$	23		$	3		$	4
Cash dividends received from consolidated subsidiaries	$	610		$	730		$	368
Noncash financing activity – dividends on common stock	$	(7	)	$	—		$	—

BASIS OF PRESENTATION

Ameren Corporation (parent company only) is a public utility holding company that conducts substantially all of its business operations through its subsidiaries. As specified in Note 5 - Long-term Debt and Equity Financings under Exhibit 99.4, Item 8, of this Current Report on Form 8-K, there are restrictions on Ameren Corporation’s (parent company only) ability to obtain funds from certain of its subsidiaries through dividends, loans or advances. In accordance with authoritative accounting guidance, Ameren Corporation (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included within the combined notes under Exhibit 99.4, Item 8, of this Current Report on Form 8-K.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. 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. 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 under Exhibit 99.4, Item 8, of this current Report on Form 8-K 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. Therefore, Ameren has segregated New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers and presented them separately as discontinued operations for all periods presented on the Condensed Statement of Income (Loss) and Comprehensive Income (Loss) and Condensed Balance sheet. See Note 16 - Divestiture Transactions and Discontinued Operations under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information regarding that presentation.

SHORT-TERM DEBT AND LIQUIDITY

See Note 4 - Short-term Debt and Liquidity under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for a description and details of short-term debt and liquidity needs of Ameren Corporation (parent company only).

LONG-TERM OBLIGATIONS

See Note 5 - Long-term Debt and Equity Financings under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for a description and details of long-term obligations of Ameren Corporation (parent company only).

COMMITMENTS AND CONTINGENCIES

See Note 14 - Related Party Transactions with New AER and Note 15 - Commitments and Contingencies under Exhibit 99.4, Item 8, of this Current Report on form 8-K for a description of all material contingencies and guarantees outstanding of Ameren Corporation (parent company only).

IMPAIRMENT

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 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 announcement that Ameren intends to exit the Merchant Generation segment before the end of the Merchant Generation's 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, in the fourth quarter of 2012, Ameren Corporation (parent company only) recorded a noncash pretax impairment charge of $1.88 billion to reduce its investment in certain of the Merchant Generation segment's coal and natural gas-fired energy centers to their estimated fair values. This charge was included within "Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations" (parent company only) in the Condensed Statement of Income (Loss) and Comprehensive Income (Loss) for the year ended December 31, 2012.

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Related Party Transactions

12 Months Ended

Dec. 31, 2012

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

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, 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 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

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Stock-Based Compensation (Summary Of Nonvested Shares) (Details) (Performance Share Units [Member], USD $)	1 Months Ended		12 Months Ended
	Jan. 31, 2012	Jan. 31, 2011	Dec. 31, 2012
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share Units, Granted			717,151	[1]
Share Units, Unearned or forfeited			(477,928)	[2]
Share Units, Earned and vested			(203,567)	[3]
Share Units, Nonvested at end of year	1,156,831		1,192,487
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted-averageFair Value per Unit, granted	$ 35.68	$ 31.41	$ 35.68	[1]
Weighted-average Fair Value per Unit, Unearned or forfeited			$ 32.04	[2]
Weighted-average Fair Value per Unit, Earned and vested			$ 34.01	[3]
Weighted-average Fair Value per Unit, Nonvested at end of year	$ 31.70		$ 33.56

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

[2] Includes share units granted in 2010 that were not earned based on performance provisions of the award grants.

[3] 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.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2012

Related Party Transaction [Line Items]

Schedule of Related Party Transactions [Table Text Block]

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

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Fair Value Measurements (Schedule of Valuation Process and Unobservable Inputs) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Fuel Oils [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	$ 8	[1]
Discounted Cash Flow [Member] | Minimum [Member] | Fuel Oils [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.21%	[2]
Counterparty credit risk	0.12%	[3],[4]
Credit risk	2.00%	[3],[4]
Discounted Cash Flow [Member] | Minimum [Member] | Power [Member]
Fair Value Inputs [Abstract]
Counterparty credit risk	0.22%	[3],[4],[5]
Credit risk	2.00%	[3],[4],[5]
Average bid/ask consensus peak and off-peak pricing	22	[3],[5]
Estimated auction price for FTRs	(281)	[2],[5]
Nodal basis	(5)	[3],[5]
Discounted Cash Flow [Member] | Minimum [Member] | Uranium [Member]
Fair Value Inputs [Abstract]
Average bid/ask consensus pricing	43	[2]
Discounted Cash Flow [Member] | Maximum [Member] | Fuel Oils [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.60%	[2]
Counterparty credit risk	1.00%	[3],[4]
Credit risk	0.00%	[3],[4]
Discounted Cash Flow [Member] | Maximum [Member] | Power [Member]
Fair Value Inputs [Abstract]
Counterparty credit risk	1.00%	[3],[4],[5]
Credit risk	5.00%	[3],[4],[5]
Average bid/ask consensus peak and off-peak pricing	47	[3],[5]
Estimated auction price for FTRs	1,851	[2],[5]
Nodal basis	(1)	[3],[5]
Discounted Cash Flow [Member] | Maximum [Member] | Uranium [Member]
Fair Value Inputs [Abstract]
Average bid/ask consensus pricing	46	[2]
Discounted Cash Flow [Member] | Weighted Average [Member] | Fuel Oils [Member]
Fair Value Inputs [Abstract]
Escalation rate	0.44%	[2]
Counterparty credit risk	1.00%	[3],[4]
Credit risk	0.00%	[3],[4]
Discounted Cash Flow [Member] | Weighted Average [Member] | Power [Member]
Fair Value Inputs [Abstract]
Counterparty credit risk	1.00%	[3],[4],[5]
Credit risk	5.00%	[3],[4],[5]
Average bid/ask consensus peak and off-peak pricing	31	[3],[5]
Estimated auction price for FTRs	178	[2],[5]
Nodal basis	(3)	[3],[5]
Discounted Cash Flow [Member] | Weighted Average [Member] | Uranium [Member]
Fair Value Inputs [Abstract]
Average bid/ask consensus pricing	44	[2]
Option Model [Member] | Minimum [Member] | Fuel Oils [Member]
Fair Value Inputs [Abstract]
Volatilities	7.00%	[2]
Option Model [Member] | Maximum [Member] | Fuel Oils [Member]
Fair Value Inputs [Abstract]
Volatilities	27.00%	[2]
Option Model [Member] | Weighted Average [Member] | Fuel Oils [Member]
Fair Value Inputs [Abstract]
Volatilities	24.00%	[2]
Fundamental Energy Production Model [Member] | Minimum [Member] | Power [Member]
Fair Value Inputs [Abstract]
Estimated future gas prices	4	[2],[5]
Fundamental Energy Production Model [Member] | Maximum [Member] | Power [Member]
Fair Value Inputs [Abstract]
Estimated future gas prices	8	[2],[5]
Fundamental Energy Production Model [Member] | Weighted Average [Member] | Power [Member]
Fair Value Inputs [Abstract]
Estimated future gas prices	6	[2],[5]
Contract Price Allocation [Member] | Minimum [Member] | Power [Member]
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	5	[2],[5]
Contract Price Allocation [Member] | Maximum [Member] | Power [Member]
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	7	[2],[5]
Contract Price Allocation [Member] | Weighted Average [Member] | Power [Member]
Fair Value Inputs [Abstract]
Estimated renewable energy credit costs	6	[2],[5]
Derivative liabilities [Member] | Fuel Oils [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	3	[1]
Derivative liabilities [Member] | Power [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	114	[1]
Derivative liabilities [Member] | Uranium [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative liabilities	2	[1]
Derivative assets [Member] | Power [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets	14	[1]
Derivative assets [Member] | Uranium [Member]
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative assets		[1]

[1] The derivative asset and liability balances are presented net of counterparty credit considerations.

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

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

[4] Counterparty credit risk is only applied to counterparties with derivative asset balances. Ameren credit risk is only applied to counterparties with derivative liability balances.

[5] 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.

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Commitments And Contingencies (Pumped-Storage Hydroelectric Facility Breach) (Details) (Union Electric Company [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Union Electric Company [Member]
Commitments and Contingencies [Line Items]
Insurance Settlements Receivable	$ 68

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Rate And Regulatory Matters (Schedule Of Regulatory Assets And Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Rate And Regulatory Matters [Line Items]
Current regulatory assets	$ 247		$ 215
Noncurrent regulatory assets	1,786		1,603
Current regulatory liabilities	100		133
Noncurrent regulatory liabilities	1,589		1,502
Under-Recovered FAC [Member]
Rate And Regulatory Matters [Line Items]
Current regulatory assets	145	[1],[2]	83	[1],[2]
Under-Recovered Illinois Electric Power Costs [Member]
Rate And Regulatory Matters [Line Items]
Current regulatory assets		[1],[3]	4	[1],[3]
Under-Recovered PGA [Member]
Rate And Regulatory Matters [Line Items]
Current regulatory assets	12	[1],[3]	8	[1],[3]
MTM Derivative Losses [Member]
Rate And Regulatory Matters [Line Items]
Current regulatory assets	90	[4]	120	[4],[5]
Noncurrent regulatory assets	135	[4]	100	[4]
Pension And Postretirement Benefit Costs [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	772	[6]	878	[6]
Income Taxes [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	235	[7]	239	[7]
Noncurrent regulatory liabilities	46	[8]	48	[8]
Asset Retirement Obligation [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	5	[9]	6	[9]
Noncurrent regulatory liabilities	80	[9]	29	[9]
Callaway Costs [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	44	[1],[10]	48	[1],[10]
Unamortized Loss On Reacquired Debt [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	181	[1],[11]	47	[1],[11]
Recoverable Costs Contaminated Facilities [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	248	[12]	102	[12]
SO2 Emission Allowances Sale Tracker [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	2	[13]	6	[13]
Storm Costs [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	9	[14]	16	[14]
Demand-Side Costs [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	73	[1],[15]	70	[1],[15]
Reserve For Workers' Compensation Liabilities [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	12	[16]	13	[16]
Bad Debt Rider [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory liabilities	12	[17]	10	[17]
Credit Facilities Fees [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	6	[16]	10	[16]
Employee Separation Costs [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	2	[18]	6	[18]
Common Stock Issuance Costs [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	7	[19]	10	[19]
Construction Accounting For Pollution Control Equipment [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	23	[1],[20]	25	[1],[20]
Other [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory assets	32	[21]	27	[21]
Noncurrent regulatory liabilities	4	[22]	2	[22]
Over-Recovered FAC [Member]
Rate And Regulatory Matters [Line Items]
Current regulatory liabilities		[23]	12	[23]
Over-Recovered Illinois Electric Power Costs [Member]
Rate And Regulatory Matters [Line Items]
Current regulatory liabilities	58	[3]	64	[3]
Over-Recovered PGA [Member]
Rate And Regulatory Matters [Line Items]
Current regulatory liabilities	15	[3]	9	[3]
MTM Derivative Gains [Member]
Rate And Regulatory Matters [Line Items]
Current regulatory liabilities	19	[24]	46	[24]
Noncurrent regulatory liabilities	2	[24]	82	[24]
Wholesale Distribution Refund [Member]
Rate And Regulatory Matters [Line Items]
Current regulatory liabilities	8	[25]	2	[25]
Removal Costs [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory liabilities	1,347	[26]	1,269	[26]
Pension And Postretirement Benefit Costs Tracker [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory liabilities	23	[27]	38	[27]
Energy Efficiency Rider [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory liabilities	20	[28]	24	[28]
IEMA Revenue Requirement Reconciliation [Member]
Rate And Regulatory Matters [Line Items]
Noncurrent regulatory liabilities	$ 55	[22]		[22]

[1] 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.

[2] Costs under- or over-recovered from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral.

[3] 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.

[4] 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.

[5] These assets earn a return.

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

[7] 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.

[8] 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.

[9] 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.

[10] 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.

[11] 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.

[12] 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.

[13] 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.

[14] 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.

[15] Reserve for workers’ compensation claims. The period of recovery will depend on the timing of actual expenditures.

[16] 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.

[17] 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.

[18] 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.

[19] 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.

[20] 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.

[21] 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.

[22] 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.

[23] Deferral of commodity-related derivative MTM gains.

[24] Estimated refund to wholesale electric customers. See 2011 Wholesale Distribution Rate Case above.

[25] Unamortized portion of investment tax credit and federal excess deferred taxes. See Note 13 - Income Taxes for amortization period.

[26] 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.

[27] 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.

[28] 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.

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Long-Term Debt And Equity Financings (Aggregate Principal Amount of Senior Notes) (Details) (USD $)		0 Months Ended						0 Months Ended						0 Months Ended						0 Months Ended						0 Months Ended					0 Months Ended
	Dec. 31, 2012 Ameren Illinois Company [Member] 2.70% Senior Notes Due 2022 [Member]	Aug. 27, 2012 Ameren Illinois Company [Member] Secured Debt [Member] Senior Secured Notes 9.75% Due 2018 [Member]		Dec. 31, 2012 Ameren Illinois Company [Member] Secured Debt [Member] Senior Secured Notes 9.75% Due 2018 [Member]		Dec. 31, 2011 Ameren Illinois Company [Member] Secured Debt [Member] Senior Secured Notes 9.75% Due 2018 [Member]		Aug. 27, 2012 Ameren Illinois Company [Member] Secured Debt [Member] Senior Secured Notes 6.25% Due 2018 [Member]		Dec. 31, 2012 Ameren Illinois Company [Member] Secured Debt [Member] Senior Secured Notes 6.25% Due 2018 [Member]		Dec. 31, 2011 Ameren Illinois Company [Member] Secured Debt [Member] Senior Secured Notes 6.25% Due 2018 [Member]		Sep. 20, 2012 Union Electric Company [Member] Secured Debt [Member] 6.00% Senior secured notes due 2018 [Member]		Dec. 31, 2012 Union Electric Company [Member] Secured Debt [Member] 6.00% Senior secured notes due 2018 [Member]		Dec. 31, 2011 Union Electric Company [Member] Secured Debt [Member] 6.00% Senior secured notes due 2018 [Member]		Sep. 20, 2012 Union Electric Company [Member] Secured Debt [Member] 6.70% Senior secured notes due 2019 [Member]		Dec. 31, 2012 Union Electric Company [Member] Secured Debt [Member] 6.70% Senior secured notes due 2019 [Member]		Dec. 31, 2011 Union Electric Company [Member] Secured Debt [Member] 6.70% Senior secured notes due 2019 [Member]		Sep. 20, 2012 Union Electric Company [Member] Secured Debt [Member] 5.10% Senior secured notes due 2018 [Member]	Dec. 31, 2012 Union Electric Company [Member] Secured Debt [Member] 5.10% Senior secured notes due 2018 [Member]		Dec. 31, 2011 Union Electric Company [Member] Secured Debt [Member] 5.10% Senior secured notes due 2018 [Member]		Sep. 20, 2012 Union Electric Company [Member] Secured Debt [Member] 5.10% Senior secured notes due 2019 [Member]		Dec. 31, 2012 Union Electric Company [Member] Secured Debt [Member] 5.10% Senior secured notes due 2019 [Member]		Dec. 31, 2011 Union Electric Company [Member] Secured Debt [Member] 5.10% Senior secured notes due 2019 [Member]		Dec. 31, 2012 Union Electric Company [Member] Secured Debt [Member] 3.90% Senior secured notes due 2042 [Member]		Sep. 20, 2012 Union Electric Company [Member] Secured Debt [Member] 3.90% Senior secured notes due 2042 [Member]	Sep. 11, 2012 Union Electric Company [Member] Secured Debt [Member] 3.90% Senior secured notes due 2042 [Member]	Dec. 31, 2011 Union Electric Company [Member] Secured Debt [Member] 3.90% Senior secured notes due 2042 [Member]		Sep. 20, 2012 Maximum [Member] Union Electric Company [Member] Secured Debt [Member] 5.10% Senior secured notes due 2018 [Member]
Debt Instrument [Line Items]
Stated interest rate on debt instrument	2.70%	9.75%		9.75%				6.25%		6.25%				6.00%		6.00%				6.70%		6.70%				5.10%	5.10%				5.10%		5.10%				3.90%		3.90%	3.90%
Principal Amount Repurchased		$ 87,000,000						$ 194,000,000						$ 71,000,000						$ 121,000,000						$ 1,000,000					$ 56,000,000
Premium Plus Accrued and Unpaid Interest		36,000,000	[1]					47,000,000	[1]					19,000,000	[2]					35,000,000	[2]										12,000,000	[2]											1,000,000
Principal Amount Outstanding After Tender Offer	$ 400,000,000	$ 313,000,000		$ 313,000,000	[3],[4]	$ 400,000,000	[3],[4]	$ 144,000,000		$ 144,000,000	[3],[4]	$ 337,000,000	[3],[4]	$ 179,000,000		$ 179,000,000	[5],[6]	$ 250,000,000	[5],[6]	$ 329,000,000		$ 329,000,000	[5],[6]	$ 450,000,000	[5],[6]	$ 199,000,000	$ 199,000,000	[6]	$ 200,000,000	[6]	$ 244,000,000		$ 244,000,000	[6]	$ 300,000,000	[6]	$ 485,000,000	[5],[6]	$ 485,000,000	$ 485,000,000	$ 0	[5],[6]

[1] 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 million 2.70% senior secured notes due 2022.

[2] 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 million 3.90% senior secured notes due 2042.

[3] 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.

[4] 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.

[5] 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.

[6] 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.

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair Value Inputs, Assets and Liabilities, Quantitative Information

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:

	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.

Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis

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:

		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.

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.

Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level 3 In The Fair Value Hierarchy

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.

Schedule Of Transfers Between Fair Value Hierarchy Levels

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	)

Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt And Preferred Stock

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.

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Short-Term Debt And Liquidity (Tables)

12 Months Ended

Dec. 31, 2012

Line of Credit Facility [Abstract]

Schedule Of Maximum Aggregate Amount Available On Credit Agreements

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

Borrowing Activity On Credit Agreements

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.

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Long-Term Debt And Equity Financings (Tables)

12 Months Ended

Dec. 31, 2012

Debt Instrument [Line Items]

Schedule of Long-term Debt Instruments

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

	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.

(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.

Schedule Of Maturities Of Long-Term Debt

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.

Schedule Of Outstanding Preferred Stock

		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.

Schedule of Required and Actual Debt Ratios

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.

Union Electric Company [Member]

Debt Instrument [Line Items]

Aggregate Principal Amount Of Maturities

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 Company [Member]

Debt Instrument [Line Items]

Aggregate Principal Amount Of Maturities

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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Short-Term Debt And Liquidity

12 Months Ended

Dec. 31, 2012

Line of Credit Facility [Abstract]

SHORT-TERM DEBT AND LIQUIDITY

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 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 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 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.

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Schedule I - Condensed Financial Information Of Parent (Impairment and Other Charges) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Impairment and Other Charges [Line Items]
Impairment charge on long-lived assets and related charges	$ 0	$ 123	$ 64
Parent Company [Member] | Merchant Generation [Member]
Impairment and Other Charges [Line Items]
Impairment charge on long-lived assets and related charges	$ 1,880

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Long-Term Debt And Equity Financings (Schedule Of Average Interest Rates) (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
1992 Series due 2022 [Member] | Union Electric Company [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate during period	0.30%	0.34%
1998 Series A due 2033 [Member] | Union Electric Company [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate during period	0.65%	0.69%
1998 Series B due 2033 [Member] | Union Electric Company [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate during period	0.64%	0.68%
1998 Series C due 2033 [Member] | Union Electric Company [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate during period	0.64%	0.69%
Series B-1 1993 Due 2028 [Member] | Ameren Illinois Company [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate during period	0.22%	0.28%

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Retirement Benefits (Funded Status Of Benefit Plans And Amounts Included In Regulatory Assets And OCI) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Amounts recognized in the consolidated balance sheet consist of:
Noncurrent liability	$ 1,138		$ 1,253
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation at end of year	3,829	[1]	3,553	[1]
Change in benefit obligation:
Net benefit obligation at beginning of year	3,764	[1]	3,366	[1]
Service cost	81	[1]	73	[1]	65
Interest cost	166	[1]	175	[1]	181
Plan amendments	0	[1],[2]	(16)	[1],[2]
Participant contributions	0	[1]	0	[1]
Actuarial (gain) loss	240	[1]	335	[1]
Benefits paid	(200)	[1]	(169)	[1]
Net benefit obligation at end of year	4,051	[1]	3,764	[1]	3,366	[1]
Change in plan assets:
Fair value of plan assets at beginning of year	2,814	[1]	2,664	[1]
Actual return on plan assets	385	[1]	223	[1]
Employer contributions	128	[1]	96	[1]	81
Participant contributions	0	[1]	0	[1]
Benefits paid	(200)	[1]	(169)	[1]
Fair value of plan assets at end of year	3,127	[1]	2,814	[1]	2,664	[1]
Funded status - deficiency	924	[1]	950	[1]
Accrued benefit cost at December 31	924	[1]	950	[1]
Amounts recognized in the consolidated balance sheet consist of:
Current liability	3	[1]	3	[1]
Noncurrent liability	921	[1]	947	[1]
Net liability recognized	924	[1]	950	[1]
Amounts recognized in regulatory assets consist of:
Net actuarial loss	699	[1]	734	[1]
Prior service cost (credit)	(6)	[1]	(7)	[1]
Transition obligation	0	[1]	0	[1]
Amounts (pretax) recognized in accumulated OCI consist of:
Net actuarial loss	65	[1]	54	[1]
Prior service cost (credit)	(14)	[1]	(16)	[1]
Total	744	[1]	765	[1]
Postretirement Benefits [Member]
Change in benefit obligation:
Net benefit obligation at beginning of year	1,145	[1]	1,036	[1]
Service cost	22	[1]	20	[1]	18
Interest cost	47	[1]	54	[1]	58
Plan amendments	0	[1]	0	[1]
Participant contributions	16	[1]	18	[1]
Actuarial (gain) loss	(10)	[1]	71	[1]
Benefits paid	(69)	[1]	(63)	[1]
Early retiree reinsurance program receipt	2	[1]	3	[1]
Federal subsidy on benefits paid	4	[1]	6	[1]
Net benefit obligation at end of year	1,157	[1]	1,145	[1]	1,036	[1]
Change in plan assets:
Fair value of plan assets at beginning of year	836	[1]	735	[1]
Actual return on plan assets	104	[1]	8	[1]
Employer contributions	45	[1]	129	[1]	36
Federal subsidy on benefits paid	4	[1]	6	[1]
Early retiree reinsurance program receipt	2	[1]	3	[1]
Participant contributions	16	[1]	18	[1]
Benefits paid	(69)	[1]	(63)	[1]
Fair value of plan assets at end of year	938	[1]	836	[1]	735	[1]
Funded status - deficiency	219	[1]	309	[1]
Accrued benefit cost at December 31	219	[1]	309	[1]
Amounts recognized in the consolidated balance sheet consist of:
Current liability	2	[1]	3	[1]
Noncurrent liability	217	[1]	306	[1]
Net liability recognized	219	[1]	309	[1]
Amounts recognized in regulatory assets consist of:
Net actuarial loss	103	[1]	177	[1]
Prior service cost (credit)	(24)	[1]	(28)	[1]
Transition obligation	0	[1]	2	[1]
Amounts (pretax) recognized in accumulated OCI consist of:
Net actuarial loss	5	[1]	5	[1]
Prior service cost (credit)	(6)	[1]	(7)	[1]
Total	$ 78	[1]	$ 149	[1]

[1] Not applicable.

[2] 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.

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Schedule II - Valuation And Qualifying Accounts

12 Months Ended

Dec. 31, 2012

Valuation and Qualifying Accounts [Abstract]

Valuation And Qualifying Accounts

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010
(in millions)
Column A	Column B		Column C				Column D		Column E
Description	Balance at Beginning of Period		(1) Charged to Costs and Expenses		(2) Charged to Other Accounts(a)		Deductions(b)		Balance at End of Period
Ameren:
Deducted from assets - allowance for doubtful accounts:
2012	$	20	$	30	$	2	$	35	$	17
2011	22		41		—		43		20
2010	24		32		—		34		22
Deferred tax valuation allowance:
2012	$	1	$	1	$	—	$	—	$	2
2011	1		—		—		—		1
2010	—		1		—		—		1

(a) Uncollectible account reserve associated with receivables purchased by Ameren Illinois from alternative retail electric suppliers as required by the Illinois Public Utility Act.

(b) Uncollectible accounts charged off, less recoveries.

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary Of Nonvested Shares Related To Long-Term Incentive Plan

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.

(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.

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Stock-Based Compensation (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended			1 Months Ended		12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Jan. 31, 2012 Performance Share Units [Member]	Jan. 31, 2011 Performance Share Units [Member]	Dec. 31, 2012 Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares available for grants	4,000,000
Share-based compensation expense	$ 22	$ 13	$ 11
Employee service share-based compensation, tax benefit from compensation expense	8	5	4
Amounts paid to settle share units	11	4	2
Compensation cost not yet recognized	$ 21
Expected weighted average recognition period for share-based compensation expense, in months	20 months
Performance period						3 years
Percentage of shares issued per share unit, minimum						0.00%
Percentage of shares issued per share unit, maximum						200.00%
Fair value of each share unit, per share				$ 35.68	$ 31.41	$ 35.68	[1]
Closing common share price				$ 33.13	$ 28.19
Three-year risk-free rate				0.41%	1.08%
Volatility rate, minimum				17.00%	22.00%
Volatility rate, maximum				31.00%	36.00%

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

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2012

Derivative Instrument Detail [Abstract]

DERIVATIVE FINANCIAL INSTRUMENTS

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.

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.

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:

	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

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Retirement Benefits (Cash Contributions Made To Benefit Plans) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Cash contributions to benefit plans	$ 128	[1]	$ 96	[1]	$ 81
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Cash contributions to benefit plans	$ 45	[1]	$ 129	[1]	$ 36

[1] Not applicable.

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Commitments And Contingencies (Schedule Of Lease Obligations) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2010
Commitments and Contingencies [Line Items]
Capital lease payments, 2013	$ 32	[1]
Capital lease payments, 2014	32	[1]
Capital lease payments, 2015	33	[1]
Capital lease payments, 2016	33	[1]
Capital lease payments, 2017	33	[1]
Capital lease payments, After 5 Years	425	[1]
Capital lease payments, Total	588	[1]
Less amount representing interest, 2013	27
Less amount representing interest, 2014	27
Less amount representing interest, 2015	27
Less amount representing interest, 2016	27
Less amount representing interest, 2017	27
Less amount representing interest, After 5 Years	149
Less amount representing interest, Total	284
Present value of minimum capital lease payments, 2013	5
Present value of minimum capital lease payments, 2014	5
Present value of minimum capital lease payments, 2015	6
Present value of minimum capital lease payments, 2016	6
Present value of minimum capital lease payments, 2017	6
Present value of minimum capital lease payments, After 5 Years	276
Present value of minimum capital lease payments, Total	304
Operating leases, 2013	19	[2]
Operating leases, 2014	14	[2]
Operating leases, 2015	14	[2]
Operating leases, 2016	14	[2]
Operating leases, 2017	14	[2]
Operating leases, After 5 Years	63	[2]
Operating leases, Total	138	[2]
Total lease obligations, 2013	24
Total lease obligations, 2014	19
Total lease obligations, 2015	20
Total lease obligations, 2016	20
Total lease obligations, 2017	20
Total lease obligations, After 5 Years	339
Total lease obligations, Total	442
Annual obligation for real estate leases and railroad licenses	2
Total rental expense	$ 33		$ 36	$ 41

[1] See Properties under Part I, Item 2, and Note 3 - Property and Plant, Net of this report for additional information

[2] 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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Derivative Financial Instruments (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Derivative Instrument Detail [Abstract]
Counterparty letters of credit held as collateral	$ 1	$ 1

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Property And Plant, Net

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

PROPERTY AND PLANT, NET

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

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Consolidated Statement Of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 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 to net cash provided by operating activities:
Impairment and other charges		123	64
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 cost		(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)
Generator advances received for construction	4	5	29
Repayments of generator 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 provided by (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 capitalized	433	453	494
Income taxes, net	$ 1	$ (61)	$ (92)

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Retirement Benefits (Assumptions Used To Determine Benefit Obligations) (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate at measurement date	4.00%	4.50%
Increase in future compensation	3.50%	3.50%
Medical cost trend rate (initial)	0.00%	0.00%
Medical cost trend rate (ultimate)	0.00%	0.00%
Years to ultimate rate	0 years	0 years
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate at measurement date	4.00%	4.50%
Increase in future compensation	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 years	1 year

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Summary Of Significant Accounting Policies (Schedule Of Asset Retirement Obligations) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance, beginning of year	$ 369	[1],[2]	$ 403	[1]
Liabilities incurred		[1]		[1]
Liabilities settled	(6)	[1]	(2)	[1]
Accretion in period	20	[1],[3]	22	[1],[3]
Change in estimates	(8)	[1],[4]	(54)	[1],[5]
Balance, end of year	375	[1]	369	[1],[2]
Nuclear decommissioning trust fund	408		357
Asset retirement obligation included in other current liabilities			$ 5

[1] 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.

[2] Balance included $5 million in "Other current liabilities" on the consolidated balance sheet as of December 31, 2011.

[3] Accretion expense was recorded as an increase to regulatory assets.

[4] 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.

[5] 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.

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Impairment and Other Charges (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended			1 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2011 Closure of Meredosia and Hutsonville Energy Centers [Member]	Dec. 31, 2011 Taum Sauk Energy Center [Member] Union Electric Company [Member]	Dec. 31, 2010 Meredosia Energy Center [Member]
Impairment and Other Charges [Line Items]
Impairment charge on long-lived assets and related charges	$ 0	$ 123	$ 64	$ 26		$ 64
Non-cash impairment of materials and supplies				4
Severance costs				4
Loss from regulatory disallowance					$ 89

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Impairment and Other Charges (Tables)

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

Impairment 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

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Income Taxes (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended				12 Months Ended	1 Months Ended		12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Jun. 30, 2011	Dec. 31, 2011 Illinois Corporate Income Tax [Member]	Jan. 31, 2011 Minimum [Member] Illinois Corporate Income Tax [Member]	Jan. 31, 2011 Maximum [Member] Illinois Corporate Income Tax [Member]	Dec. 31, 2015 Income Tax Rate in 2015 [Member] Illinois Corporate Income Tax [Member]	Dec. 31, 2025 Income Tax Rate in 2025 [Member] Illinois Corporate Income Tax [Member]
Income Taxes [Line Items]
State corporate income tax rate	5.00%	4.00%	5.00%			7.30%	9.50%	7.75%	7.30%
Increase in current state and local tax expense benefit					$ 6
Decrease in deferred state and local income tax expense benefit					2
Reduction of uncertain tax positions				39
Estimated unrecognized tax benefits, decreases resulting from settlements with taxing authorities	$ 143

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Fair Value Measurements (Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt And Preferred Stock) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt and Capital Lease Obligations	$ 6,157	[1]	$ 6,032	[1]
Preferred stock	142	[1]	142	[1]
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt and capital lease obligations (including current portion)	7,110	[1]	6,961	[1]
Preferred stock	$ 123	[1]	$ 92	[1]

[1] Preferred stock along with the noncontrolling interest of EEI is recorded in "Noncontrolling Interests" on the consolidated balance sheet.

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Related Party Transactions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction [Line Items]
Total Operating Revenues	$ 17	$ 12	$ 11
Ameren Missouri and Genco Gas Transportation Agreement [Member]
Related Party Transaction [Line Items]
Total Operating Revenues	1	1	1
Ameren Illinois Transmission Services Agreement with Marketing Company [Member]
Related Party Transaction [Line Items]
Total Operating Revenues	16	11	10
Ameren Illinois Power Supply Agreements with Marketing Company [Member]
Related Party Transaction [Line Items]
Operating Expenses	311	232	233
Ameren Illinois gas purchases from Genco [Member]
Related Party Transaction [Line Items]
Operating Expenses			$ 1

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Rate And Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2012

Public Utilities, General Disclosures [Abstract]

Schedule Of Regulatory Assets And Liabilities

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.

(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.

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Retirement Benefits (Schedule Of Potential Changes In Key Assumptions) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost and Interest Cost, .25% decrease in discount rate	$ (2)
Benefit Obligation, .25% decrease in discount rate	121
Service Cost and Interest Cost, .25% increase in salary rate	2
Benefit Obligation, .25% increase in salary rate	13
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation, .25% decrease in discount rate	34
Service Cost and Interest Cost, 1.00% increase in annual medical trend	0
Benefit Obligation, 1.00% increase in annual medical trend	36
Service Cost and Interest Cost, 1.00% decrease in annual medical trend	(1)
Benefit Obligation, 1.00% decrease in annual medical trend	$ (34)

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Retirement Benefits (Summary Of Benefit Plan Costs Incurred) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 111	$ 77	$ 62
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 14	$ 23	$ 21

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Fair Value Measurements (Schedule Of Transfers Between Fair Value Hierarchy Levels) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transfer into of Level 3/Transfers out of Level 2
Net fair value of Level 3 transfers	182	(19)
Fuel Oils [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transfers into Level 3/Transfers out of Level 1	1
Transfers out of Level 3/Transfers into Level1		(19)
Natural Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transfers out of Level 3/Transfers into Level 2	185
Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transfer into of Level 3/Transfers out of Level 2		(1)
Transfers out of Level 3/Transfers into Level 2	$ (4)	$ 1

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Retirement Benefits (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 bond	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Other non-current assets	$ 667	$ 760
Number of high-quality corporate bonds	600
Defined benefit plan, estimated future employer contributions during the next five years	525
Actual return in excess of (or less than) expected return, percentage	25.00%
Expected return on plan assets, period	4 years
Amortization basis, straight line, in years	10 years
Number Of Employees Who Moved To A Cash Balance Formula [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of employees	430
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Assumptions used calculating net periodic benefit cost, expected long-term return on assets in 2013	7.50%
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Assumptions used calculating net periodic benefit cost, expected long-term return on assets in 2013	7.25%
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, estimated future employer contributions during the next five years	50
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, estimated future employer contributions during the next five years	150
Private equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of limited partnerships in private equity funds	10
Minimum invested capital within limited partnership investments	0.1
Maximum invested capital within limited partnership investments	5
Illinois Power Holdings, LLC [Member]
Defined Benefit Plan Disclosure [Line Items]
Transaction Agreement, Pension and Other Postretirement Obligations Assumed by Counterparty	40
Transaction Agreement, Defined Benefit Plan Assets Assumed by Counterparty	$ 15

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Long-Term Debt And Equity Financings (Schedule of Required and Actual Debt Ratios) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Union Electric Company [Member]
Debt Instrument [Line Items]
Bonds Issuable Based On Coverage Ratio	$ 4,056	[1]
Preferred Stock Issuable Based On Coverage Ratio	2,351
Retired Bond Capacity	485
Union Electric Company [Member] | Minimum Required Ratio [Member] | Minimum [Member]
Debt Instrument [Line Items]
Interest Coverage Ratio	2.0	[2]
Dividend Coverage Ratio	2.5	[3]
Union Electric Company [Member] | Actual Ratio [Member]
Debt Instrument [Line Items]
Interest Coverage Ratio	4.6
Dividend Coverage Ratio	122.8
Ameren Illinois Company [Member]
Debt Instrument [Line Items]
Bonds Issuable Based On Coverage Ratio	3,439	[1],[4]
Preferred Stock Issuable Based On Coverage Ratio	203
Retired Bond Capacity	$ 645
Ameren Illinois Company [Member] | Minimum Required Ratio [Member] | Minimum [Member]
Debt Instrument [Line Items]
Interest Coverage Ratio	2.0	[2]
Dividend Coverage Ratio	1.5	[3]
Ameren Illinois Company [Member] | Actual Ratio [Member]
Debt Instrument [Line Items]
Interest Coverage Ratio	7.1
Dividend Coverage Ratio	2.8

[1] 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.

[2] 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.

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

[4] Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.

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Commitments And Contingencies (Schedule Of Estimated Purchased Power Commitments) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2013	$ 1,563
2014	1,434
2015	1,122
2016	937
2017	898
Thereafter	1,659
Total	7,613
Coal [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2013	620
2014	625
2015	614
2016	644
2017	676
Thereafter	245
Total	3,424
Natural Gas [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2013	327
2014	249
2015	136
2016	54
2017	34
Thereafter	105
Total	905
Nuclear Fuel [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2013	36
2014	89
2015	87
2016	95
2017	78
Thereafter	277
Total	662
Purchased Power [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2013	421	[1]
2014	309	[1]
2015	164	[1]
2016	78	[1]
2017	55	[1]
Thereafter	687	[1]
Total	1,714	[1]
Renewable energy credits agreements, term	20 years
Methane Gas [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2013	3
2014	3
2015	4
2016	4
2017	5
Thereafter	99
Total	118
Other [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2013	156
2014	159
2015	117
2016	62
2017	50
Thereafter	246
Total	790
Ameren Illinois Company [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Long-term purchase commitment, cubic feet to be purchased	15,500
Gas transportation agreements, term	10 years
Investment in Energy Efficiency Programs [Member] | Union Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Other commitment	$ 147
Other commitments, term	3 years

[1] 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.

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Short-Term Debt And Liquidity (Borrowing Activity On Credit Agreements) (Details) (2010 Missouri Credit Agreement [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Line of Credit Facility [Line Items]
Average daily borrowings outstanding	$ 1	[1]	$ 105
Weighted-average interest rate	4.15%	[1]	2.30%
Peak credit facility borrowings	50	[1]	340
Peak interest rate	4.15%		4.30%
Parent Company [Member]
Line of Credit Facility [Line Items]
Average daily borrowings outstanding			105
Weighted-average interest rate			2.30%
Peak credit facility borrowings			340
Peak interest rate			4.30%
Union Electric Company [Member]
Line of Credit Facility [Line Items]
Average daily borrowings outstanding	1	[1]
Weighted-average interest rate	4.15%	[1]
Peak credit facility borrowings	$ 50	[1]
Peak interest rate	4.15%

[1] Calculated through termination date.

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Nuclear Decommissioning Trust Fund Investments (Proceeds From The Sale Of Investments And Related Gross Realized Gains And Losses In Nuclear Decommissioning Trust Fund) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Nuclear Decommissioning Trust Fund Investments [Line Items]
Sales and maturities of securities - nuclear decommissioning trust fund	$ 384	$ 199	$ 256
Gross realized gains	6	5	5
Gross realized losses	$ 2	$ 4	$ 4
Minimum [Member] | Nuclear Decommissioning Trust Fund [Member]
Nuclear Decommissioning Trust Fund Investments [Line Items]
Trust fund investments, target allocation percentage	60.00%
Maximum [Member] | Nuclear Decommissioning Trust Fund [Member]
Nuclear Decommissioning Trust Fund Investments [Line Items]
Trust fund investments, target allocation percentage	70.00%

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Callaway Energy Center

12 Months Ended

Dec. 31, 2012

Nuclear Waste Matters [Abstract]

CALLAWAY ENERGY CENTER

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 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.

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.

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Other Income And Expenses

12 Months Ended

Dec. 31, 2012

Other Nonoperating Income (Expense) [Abstract]

OTHER INCOME AND EXPENSES

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.

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Divestiture Transactions and Discontinued Operations (Components of Discontinued Operations in Consolidated Statement of Income) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended						6 Months Ended	12 Months Ended			3 Months Ended	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010		Jun. 30, 2013 New Ameren Energy Resources Company, LLC [Member]	Dec. 31, 2012 Merchant Generation [Member]	Dec. 31, 2011 Merchant Generation [Member]	Dec. 31, 2010 Merchant Generation [Member]	Mar. 31, 2012 Merchant Generation [Member] Duck Creek Energy Center [Member]	Dec. 31, 2010 Medina Valley Energy Center [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenues	$ 1,047		$ 1,278		$ 1,369
Operating expenses	(3,478)	[1]	(1,048)		(1,578)	[2]
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)
Impairment of assets to be disposed of							168	1,950	2	420	628	36
Impairment of Long-Lived Assets Held-for-use	0		123		64
Property, Plant and Equipment, Net	$ 15,348	[3]	$ 14,848	[3]

[1] 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.

[2] 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.

[3] 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.

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Derivative Financial Instruments (Open Gross Derivative Volumes By Commodity Type) (Details)	Dec. 31, 2012 T		Dec. 31, 2011 T
Accrual and Normal Purchases and Normal Sales Contracts [Member] | Coal [Member]
Derivative [Line Items]
Quantity	96,000,000	[1]	116,000,000	[1]
Accrual and Normal Purchases and Normal Sales Contracts [Member] | Natural Gas [Member]
Derivative [Line Items]
Quantity	20,000,000	[1]	50,000,000	[1]
Accrual and Normal Purchases and Normal Sales Contracts [Member] | Power [Member]
Derivative [Line Items]
Quantity	24,000,000	[1]	12,000,000	[1]
Accrual and Normal Purchases and Normal Sales Contracts [Member] | Renewable energy credits [Member]
Derivative [Line Items]
Quantity	15,000,000	[1],[2]	16,000,000	[1],[2]
Accrual and Normal Purchases and Normal Sales Contracts [Member] | Uranium [Member]
Derivative [Line Items]
Quantity	5,142,000	[1]	5,553,000	[1]
Other Contract [Member] | Natural Gas [Member]
Derivative [Line Items]
Quantity		[3]	9,000,000	[3]
Other Contract [Member] | Power [Member]
Derivative [Line Items]
Quantity	2,000,000	[3]	1,000,000	[3]
Derivatives That Qualify for Regulatory Deferral [Member] | Fuel Oils [Member]
Derivative [Line Items]
Quantity	70,000,000	[4],[5]	53,000,000	[4],[5]
Derivatives That Qualify for Regulatory Deferral [Member] | Natural Gas [Member]
Derivative [Line Items]
Quantity	147,000,000	[5]	193,000,000	[5]
Derivatives That Qualify for Regulatory Deferral [Member] | Power [Member]
Derivative [Line Items]
Quantity	23,000,000	[5]	21,000,000	[5]
Derivatives That Qualify for Regulatory Deferral [Member] | Uranium [Member]
Derivative [Line Items]
Quantity	446,000	[5]	148,000	[5]

[1] 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.

[2] 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.

[3] As of December 31, 2012, these contracts ran through December 2014 for power.

[4] Fuel oils consist of heating and crude oil.

[5] 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.

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Income Taxes

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

INCOME TAXES

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.

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

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2012 segment		Dec. 31, 2011		Dec. 31, 2010
Segment Reporting Information [Line Items]
Number of reportable segments																	3
External revenues	$ 1,258	[1]	$ 1,709	[1]	$ 1,402	[1]	$ 1,412	[1]	$ 1,296	[1]	$ 1,876	[1]	$ 1,458	[1]	$ 1,597	[1]	$ 5,781		$ 6,227		$ 6,269
Depreciation and amortization																	667		646		627
Interest and dividend income																	4	[2]	3		4
Interest Expense																	391		387		415
Income taxes (benefit)																	309		245		274
Income (Loss) from Continuing Operations Attributable to Parent	15	[1]	305	[1]	161	[1]	37	[1]	(1)	[1]	265	[1]	116	[1]	38	[1]	518		418		483
Capital expenditures																	1,063		881		941
TOTAL ASSETS	22,219								23,723								22,219		23,723
Impairment and other charges																			123		64
Union Electric Company [Member]
Segment Reporting Information [Line Items]
External revenues																	3,252		3,360		3,180
Intersegment revenues																	20		23		17
Depreciation and amortization																	440		408		382
Interest and dividend income																	32		30		31
Interest Expense																	223		209		213
Income taxes (benefit)																	252		161		199
Income (Loss) from Continuing Operations Attributable to Parent																	416		287		364
Capital expenditures																	595		550		624
TOTAL ASSETS	13,043								12,757								13,043		12,757		12,504
Ameren Illinois Company [Member]
Segment Reporting Information [Line Items]
External revenues																	2,524		2,784		3,012
Intersegment revenues																	1		3		2
Depreciation and amortization																	221		215		210
Interest and dividend income																			1		1
Interest and dividend income
Interest Expense																	129		136		143
Income taxes (benefit)																	94		127		137
Income (Loss) from Continuing Operations Attributable to Parent																	141		193		208
Capital expenditures																	442		351		281
TOTAL ASSETS	7,282								7,213								7,282		7,213		7,406
Other Segment [Member]
Segment Reporting Information [Line Items]
External revenues																	5		83		77
Intersegment revenues																	3		3
Depreciation and amortization																	6		23		35
Interest and dividend income
Interest Expense																	39		42		59
Income taxes (benefit)																	(37)		(43)		(62)
Income (Loss) from Continuing Operations Attributable to Parent																	(39)		(62)		(89)
Capital expenditures																	26		(20)	[3]	36
TOTAL ASSETS	1,228								1,211								1,228		1,211		1,354
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Intersegment revenues																	(24)		(29)		(19)
Interest and dividend income
Interest Expense
TOTAL ASSETS	(934)								(1,176)								(934)		(1,176)		(1,541)
Segment, Continuing Operations [Member]
Segment Reporting Information [Line Items]
External revenues																	5,781		6,227		6,269
Depreciation and amortization																	667		646		627
Interest and dividend income																	32		31		32
Interest Expense																	391		387		415
Income taxes (benefit)																	309		245		274
Income (Loss) from Continuing Operations Attributable to Parent																			418		483
Capital expenditures																	1,063		881		941
TOTAL ASSETS	$ 20,619	[4]							$ 20,005	[4]							$ 20,619	[4]	$ 20,005	[4]	$ 19,723	[4]

[1] 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.

[2] 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.

[3] Includes the elimination of intercompany transfers.

[4] See Note 16 - Divestiture Transactions and Discontinued Operations for additional information

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Retirement Benefits

12 Months Ended

Dec. 31, 2012

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

RETIREMENT BENEFITS

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.

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

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.

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.

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.

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.

(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:

	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.

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Schedule I - Condensed Financial Information Of Parent (Statement of Income) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2010
Condensed Financial Statements, Captions [Line Items]
Operating revenues	$ 1,258	[1]	$ 1,709	[1]	$ 1,402	[1]	$ 1,412	[1]	$ 1,296	[1]	$ 1,876	[1]	$ 1,458	[1]	$ 1,597	[1]	$ 5,781		$ 6,227	$ 6,269
Impairment and other charges																			123	64
Operating expenses																	4,590		5,216	5,144
Operating Income	111	[1],[2]	578	[1],[2]	344	[1],[2]	158	[1],[2]	91	[1],[2]	494	[1],[2]	270	[1],[2]	156	[1],[2]	1,191		1,011	1,125
Interest income from affiliates																	4	[3]	3	4
Miscellaneous expense																	70		68	88
Other Nonoperating Expense																	37		23	32
Interest charges																	(391)		(387)	(415)
Income tax (benefit)																	309		245	274
Continuing Operations	15	[1]	305	[1]	161	[1]	37	[1]	(1)	[1]	265	[1]	116	[1]	38	[1]	518		418	483
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	(1,171)	[1]	69	[1]	50	[1]	(440)	[1]	26	[1]	20	[1]	22	[1]	33	[1]	(1,492)		101	(344)
Net income (Loss) Attributable to Ameren Corporation	(1,156)	[1]	374	[1]	211	[1]	(403)	[1]	25	[1]	285	[1]	138	[1]	71	[1]	(974)		519	139
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 (Loss) from Continuing Operations, Net of Tax, Portion Attributable to Parent																	510		399	493
Comprehensive Income from Continuing Operations																	(932)		486	135
Other Comprehensive Income (Loss), Taxes:
Pension and other postretirement activity, tax (benefit)																	(6)		(14)	6
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest																	58		(20)	(16)
Comprehensive Income (Loss) from Discontinued Operations, Net of Tax, Portion Attributable to Parent																	(1,442)		87	(358)
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Operating revenues
Impairment and other charges
Operating expenses																	17		13	19
Operating Income																	(17)		(13)	(19)
Equity in earnings of subsidiaries																	548		451	525
Interest income from affiliates																	3		5	8
Other Nonoperating Expense																	4		4	3
Interest charges																	(39)		(41)	(56)
Income tax (benefit)																	(27)		(20)	(28)
Continuing Operations																	518		418	483
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent																	(1,492)		101	(344)
Net income (Loss) Attributable to Ameren Corporation																	(974)		519	139
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 (Loss) from Continuing Operations, Net of Tax, Portion Attributable to Parent																	510		399	493
Comprehensive Income from Continuing Operations																	(932)		486	135
Other Comprehensive Income (Loss), Taxes:
Unrealized net gain (loss) on derivative hedging instruments, tax (benefit)																	12		1	(1)
Reclassification adjustments for derivative (gain) included in net income, tax																	1		(3)	5
Pension and other postretirement activity, tax (benefit)																	22		(32)	6
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest																	50		(14)	(14)
Comprehensive Income (Loss) from Discontinued Operations, Net of Tax, Portion Attributable to Parent																	$ (1,442)		$ 87	$ (358)

[1] 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.

[2] 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.

[3] 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.

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Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Income Taxes [Line Items]
Statutory federal income tax rate:	35.00%		35.00%		35.00%
Depreciation differences	(1.00%)		(1.00%)		(3.00%)
Amortization of investment tax credit	(1.00%)		(1.00%)		(1.00%)
State tax	5.00%		4.00%		5.00%
Reserve for uncertain tax positions			1.00%		(1.00%)
Tax credits			(1.00%)		(1.00%)
Change in federal tax law		[1]		[1]	2.00%	[1]
Permanent items	(1.00%)	[2]		[2]		[2]
Effective income tax rate	37.00%		37.00%		36.00%

[1] 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.

[2] Permanent items are treated differently for book and tax purposes and primarily include nondeductible expense related to lobbying and stock issuance expenses.

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Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2012	Jan. 31, 2013	Jun. 30, 2012
Document Type	8-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Trading Symbol	AEE
Entity Registrant Name	AMEREN CORP
Entity Central Index Key	0001002910
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		242,634,671
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 8,137,966,865
Entity Well-known Seasoned Issuer	Yes

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Nuclear Decommissioning Trust Fund Investments (Fair Values Of Investments In Debt And Equity Securities In Nuclear Decommissioning Trust Fund) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Nuclear Decommissioning Trust Fund Investments [Line Items]
Cost	$ 281		$ 261
Gross unrealized gains	138		108
Gross unrealized loss	11		12
Fair value	408		357
Debt Securities [Member]
Nuclear Decommissioning Trust Fund Investments [Line Items]
Cost	133		114
Gross unrealized gains	8		7
Fair value	141		121
Equity Securities [Member]
Nuclear Decommissioning Trust Fund Investments [Line Items]
Cost	145		145
Gross unrealized gains	130		101
Gross unrealized loss	11		12
Fair value	264		234
Cash [Member]
Nuclear Decommissioning Trust Fund Investments [Line Items]
Cost	1		3
Fair value	1		3
Other Debt And Equity Securities [Member]
Nuclear Decommissioning Trust Fund Investments [Line Items]
Cost	2	[1]	(1)	[1]
Fair value	$ 2	[1]	$ (1)	[1]

[1] Represents payables relating to pending security purchases, net of receivables related to pending security sales and interest receivables.

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Schedule I - Condensed Financial Information Of Parent (Statement of Cash Flows) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	$ 1,690	$ 1,878	$ 1,823
Cash Flows From Investing Activities:
Other	2	12	2
Net cash used in investing activities	(1,310)	(1,048)	(1,096)
Cash flows from financing activities:
Dividends on common stock	(382)	(375)	(368)
Short-term debt and credit facility borrowings, net	(148)	(481)	(221)
Issuances:
Long-term debt	882
Common stock		65	80
Net cash provided by (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	248	538
Cash and cash equivalents at end of year	184	248	538
Noncash financing activity – dividends on common stock	(7)
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	532	804	241
Cash Flows From Investing Activities:
Money pool advances, net	24	(276)	18
Intercompany notes receivable, net	(20)	358	242
Investments in subsidiaries	(2)	(94)	(13)
Return of investments	21	3	1
Other	(5)	(5)
Net cash used in investing activities	18	(14)	248
Cash flows from financing activities:
Dividends on common stock	(382)	(375)	(368)
Short-term debt and credit facility borrowings, net	(148)	(481)	(221)
Issuances:
Common stock		65	80
Net cash provided by (used in) financing activities	(530)	(791)	(509)
Net change in cash and cash equivalents	20	(1)	(20)
Cash and cash equivalents at beginning of year	3	4	24
Cash and cash equivalents at end of year	23	3	4
Cash dividends received from consolidated subsidiaries	610	730	368
Noncash financing activity – dividends on common stock	$ (7)

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

STOCK-BASED COMPENSATION

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.

(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.

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Long-Term Debt And Equity Financings (Schedule Of Long-Term Debt Outstanding) (Details) (USD $)					12 Months Ended				12 Months Ended		12 Months Ended		12 Months Ended							12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended					12 Months Ended					12 Months Ended					12 Months Ended					12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended						12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended					12 Months Ended					12 Months Ended					12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended			12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Parent Company [Member]	Dec. 31, 2011 Parent Company [Member]	Dec. 31, 2012 Parent Company [Member] 8.875% Senior unsecured notes due 2014 [Member]	Dec. 31, 2011 Parent Company [Member] 8.875% Senior unsecured notes due 2014 [Member]	Dec. 31, 2012 Union Electric Company [Member]	Dec. 31, 2011 Union Electric Company [Member]	Dec. 31, 2012 Union Electric Company [Member] City Of Bowling Green Capital Lease Peno Creek Ct [Member]	Dec. 31, 2011 Union Electric Company [Member] City Of Bowling Green Capital Lease Peno Creek Ct [Member]	Dec. 31, 2012 Union Electric Company [Member] Audrain County Capital Lease Audrain County Ct [Member]	Dec. 31, 2011 Union Electric Company [Member] Audrain County Capital Lease Audrain County Ct [Member]	Dec. 31, 2012 Ameren Illinois Company [Member]	Dec. 31, 2011 Ameren Illinois Company [Member]	Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 5.25% Senior secured notes due 2012 [Member]		Sep. 20, 2012 Secured Debt [Member] Union Electric Company [Member] 5.25% Senior secured notes due 2012 [Member]	Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 5.25% Senior secured notes due 2012 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 4.65% Senior secured notes due 2013 [Member]		Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 4.65% Senior secured notes due 2013 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 5.50% Senior secured notes due 2014 [Member]		Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 5.50% Senior secured notes due 2014 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 4.75% Senior secured notes due 2015 [Member]		Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 4.75% Senior secured notes due 2015 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 5.40% Senior secured notes due 2016 [Member]		Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 5.40% Senior secured notes due 2016 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 6.40% Senior secured notes due 2017 [Member]		Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 6.40% Senior secured notes due 2017 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 6.00% Senior secured notes due 2018 [Member]		Sep. 20, 2012 Secured Debt [Member] Union Electric Company [Member] 6.00% Senior secured notes due 2018 [Member]	Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 6.00% Senior secured notes due 2018 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 5.10% Senior secured notes due 2018 [Member]		Sep. 20, 2012 Secured Debt [Member] Union Electric Company [Member] 5.10% Senior secured notes due 2018 [Member]	Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 5.10% Senior secured notes due 2018 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 6.70% Senior secured notes due 2019 [Member]		Sep. 20, 2012 Secured Debt [Member] Union Electric Company [Member] 6.70% Senior secured notes due 2019 [Member]	Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 6.70% Senior secured notes due 2019 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 5.10% Senior secured notes due 2019 [Member]		Sep. 20, 2012 Secured Debt [Member] Union Electric Company [Member] 5.10% Senior secured notes due 2019 [Member]	Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 5.10% Senior secured notes due 2019 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 5.00% Senior secured notes due 2020 [Member]		Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 5.00% Senior secured notes due 2020 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 5.50% Senior secured notes due 2034 [Member]		Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 5.50% Senior secured notes due 2034 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 5.30% Senior secured notes due 2037 [Member]		Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 5.30% Senior secured notes due 2037 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 8.45% Senior secured notes due 2039 [Member]		Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 8.45% Senior secured notes due 2039 [Member]		Dec. 31, 2012 Secured Debt [Member] Union Electric Company [Member] 3.90% Senior secured notes due 2042 [Member]		Sep. 20, 2012 Secured Debt [Member] Union Electric Company [Member] 3.90% Senior secured notes due 2042 [Member]	Sep. 11, 2012 Secured Debt [Member] Union Electric Company [Member] 3.90% Senior secured notes due 2042 [Member]	Dec. 31, 2011 Secured Debt [Member] Union Electric Company [Member] 3.90% Senior secured notes due 2042 [Member]		Dec. 31, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 8.875% Due 2013 [Member]		Dec. 31, 2011 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 8.875% Due 2013 [Member]		Dec. 31, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.20% Due 2016 [Member]		Dec. 31, 2011 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.20% Due 2016 [Member]		Dec. 31, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.25% Due 2016 [Member]		Dec. 31, 2011 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.25% Due 2016 [Member]		Dec. 31, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.125% Due 2017 [Member]		Dec. 31, 2011 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.125% Due 2017 [Member]		Dec. 31, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.25% Due 2018 [Member]		Aug. 27, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.25% Due 2018 [Member]	Dec. 31, 2011 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.25% Due 2018 [Member]		Dec. 31, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 9.75% Due 2018 [Member]		Aug. 27, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 9.75% Due 2018 [Member]	Dec. 31, 2011 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 9.75% Due 2018 [Member]		Dec. 31, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes, 2 Point 70, Due 2022 [Member]		Aug. 20, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes, 2 Point 70, Due 2022 [Member]	Dec. 31, 2011 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes, 2 Point 70, Due 2022 [Member]		Dec. 31, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.125% Due 2028 [Member]		Dec. 31, 2011 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.125% Due 2028 [Member]		Dec. 31, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.70% Due 2036 [Member]		Dec. 31, 2011 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.70% Due 2036 [Member]		Dec. 31, 2012 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.70% Due 2036 [Member]		Dec. 31, 2011 Secured Debt [Member] Ameren Illinois Company [Member] Senior Secured Notes 6.70% Due 2036 [Member]		Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Union Electric Company [Member] 1992 Series due 2022 [Member]		Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Union Electric Company [Member] 1992 Series due 2022 [Member]		Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Union Electric Company [Member] 1993 5.45% Series due 2028 [Member]		Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Union Electric Company [Member] 1993 5.45% Series due 2028 [Member]		Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Union Electric Company [Member] 1998 Series A due 2033 [Member]		Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Union Electric Company [Member] 1998 Series A due 2033 [Member]		Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Union Electric Company [Member] 1998 Series B due 2033 [Member]		Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Union Electric Company [Member] 1998 Series B due 2033 [Member]		Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Union Electric Company [Member] 1998 Series C due 2033 [Member]		Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Union Electric Company [Member] 1998 Series C due 2033 [Member]		Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series1992 B 6.20% Due 2012 [Member]		Nov. 30, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series1992 B 6.20% Due 2012 [Member]	Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series1992 B 6.20% Due 2012 [Member]	Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series A 2000 5.50% Due 2014 [Member]	Aug. 27, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series A 2000 5.50% Due 2014 [Member]	Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series A 2000 5.50% Due 2014 [Member]	Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series1993 5.90% Due 2023 [Member]		Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series1993 5.90% Due 2023 [Member]		Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series1994A 5.70% Due 2024 [Member]		Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series1994A 5.70% Due 2024 [Member]		Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series C-1 1993 5.95% Due 2026 [Member]		Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series C-1 1993 5.95% Due 2026 [Member]		Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series C-2 1993 5.70% Due 2026 [Member]		Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series C-2 1993 5.70% Due 2026 [Member]		Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series B-1 1993 Due 2028 [Member]		Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series B-1 1993 Due 2028 [Member]		Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series1998A 5.40% Due 2028 [Member]		Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series1998A 5.40% Due 2028 [Member]		Dec. 31, 2012 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series1998B 5.40% Due 2028 [Member]		Dec. 31, 2011 Environmental Improvement And Pollution Control Revenue Bonds [Member] Ameren Illinois Company [Member] Series1998B 5.40% Due 2028 [Member]
Debt Instrument [Line Items]
Debt instrument face amount					$ 425,000,000	$ 425,000,000									$ 0	[1]		$ 173,000,000	[1]	$ 200,000,000	[1]	$ 200,000,000	[1]	$ 104,000,000	[1]	$ 104,000,000	[1]	$ 114,000,000	[1]	$ 114,000,000	[1]	$ 260,000,000	[1]	$ 260,000,000	[1]	$ 425,000,000	[1]	$ 425,000,000	[1]	$ 179,000,000	[1],[2]	$ 179,000,000	$ 250,000,000	[1],[2]	$ 199,000,000	[1]	$ 199,000,000	$ 200,000,000	[1]	$ 329,000,000	[1],[2]	$ 329,000,000	$ 450,000,000	[1],[2]	$ 244,000,000	[1]	$ 244,000,000	$ 300,000,000	[1]	$ 85,000,000	[1]	$ 85,000,000	[1]	$ 184,000,000	[1]	$ 184,000,000	[1]	$ 300,000,000	[1]	$ 300,000,000	[1]	$ 350,000,000	[1],[2]	$ 350,000,000	[1],[2]	$ 485,000,000	[1],[2]	$ 485,000,000	$ 485,000,000	$ 0	[1],[2]	$ 150,000,000	[3],[4]	$ 150,000,000	[3],[4]	$ 54,000,000	[3]	$ 54,000,000	[3]	$ 75,000,000	[5]	$ 75,000,000	[5]	$ 250,000,000	[5],[6]	$ 250,000,000	[5],[6]	$ 144,000,000	[5],[6]	$ 144,000,000	$ 337,000,000	[5],[6]	$ 313,000,000	[5],[6]	$ 313,000,000	$ 400,000,000	[5],[6]	$ 400,000,000	[5],[6]	$ 400,000,000		[5],[6]	$ 60,000,000	[5]	$ 60,000,000	[5]	$ 61,000,000	[5]	$ 61,000,000	[5]	$ 42,000,000	[3]	$ 42,000,000	[3]	$ 47,000,000	[7],[8]	$ 47,000,000	[7],[8]	$ 44,000,000	[9]	$ 44,000,000	[9]	$ 60,000,000	[7],[8]	$ 60,000,000	[7],[8]	$ 50,000,000	[7],[8]	$ 50,000,000	[7],[8]	$ 50,000,000	[7],[8]	$ 50,000,000	[7],[8]		[10]		$ 1,000,000			$ 51,000,000	$ 32,000,000	[10]	$ 32,000,000	[10]	$ 36,000,000	[11]	$ 36,000,000	[11]	$ 35,000,000	[12]	$ 35,000,000	[12]	$ 8,000,000	[12]	$ 8,000,000	[12]	$ 17,000,000	[12],[7]	$ 17,000,000	[12],[7]	$ 19,000,000	[11]	$ 19,000,000	[11]	$ 33,000,000	[11]	$ 33,000,000	[11]
Capital lease obligations									64,000,000	69,000,000	240,000,000	240,000,000
Fair-market value adjustments													4,000,000	5,000,000
Long-term debt, gross							4,013,000,000	3,955,000,000					1,733,000,000	1,666,000,000
Less: Unamortized discount and premium			1,000,000	1,000,000			7,000,000	5,000,000					6,000,000	8,000,000
Less: Maturities due within one year	(355,000,000)	(179,000,000)					(205,000,000)	(178,000,000)					(150,000,000)	(1,000,000)
Long-term Debt, Net	$ 5,802,000,000	$ 5,853,000,000	$ 424,000,000	$ 424,000,000			$ 3,801,000,000	$ 3,772,000,000					$ 1,577,000,000	$ 1,657,000,000
Long-term debt interest rate					8.875%										5.25%		5.25%			4.65%				5.50%				4.75%				5.40%				6.40%				6.00%		6.00%			5.10%		5.10%			6.70%		6.70%			5.10%		5.10%			5.00%				5.50%				5.30%				8.45%				3.90%		3.90%	3.90%			8.875%				6.20%				6.25%				6.125%				6.25%		6.25%			9.75%		9.75%			2.70%		2.70%			6.125%				6.70%				6.70%								5.45%																6.20%		6.20%		5.50%	5.50%		5.90%				5.70%				5.95%				5.70%								5.40%				5.40%
Long-term debt maturity date					2014				2022		2033				2012					2013				2014				2015				2016				2017				2018					2018					2019					2019					2020				2034				2037				2039				2042						2013				2016				2016				2017				2018					2018					2022					2028				2036				2036				2022				2028				2033				2033				2033				2012				2014			2023				2024				2026				2026				2028				2028				2028
Debt instrument, interest rate, maximum																																																																																																																													18.00%								18.00%				18.00%				18.00%
Redemption price, percentage																																																																																																																																	100.00%																							100.00%				100.00%				100.00%				100.00%				100.00%				100.00%				100.00%

[1] 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.

[2] 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.

[3] 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.

[4] 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.

[5] 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.

[6] 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.

[7] 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 2011Ameren Missouri 1992 Series0.30% 0.34%Ameren Missouri 1998 Series A0.65% 0.69%Ameren Missouri 1998 Series B0.64% 0.68%Ameren Missouri 1998 Series C0.64% 0.69%Ameren Illinois 1993 Series B-10.22% 0.28%

[8] 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.

[9] 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.

[10] 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.

[11] 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.

[12] The bonds are callable at 100% of par value.

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Income Taxes (Schedule Of Changes To Unrecognized Tax Benefits And Related Interest) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits	$ 148	$ 246	$ 135
Increases based on tax positions	5	22	72
Decreases based on tax positions	(13)	(125)	(38)
Increases based on tax positions related to current period	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	156	148	246
Total unrecognized tax benefits that, if recognized, would impact the effective tax rates	$ 1	$ 1

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Long-Term Debt And Equity Financings (Narrative) (Details) (USD $)	12 Months Ended							12 Months Ended	1 Months Ended				0 Months Ended					0 Months Ended						0 Months Ended					0 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2011 401 (K) [Member]	Dec. 31, 2010 401 (K) [Member]	Dec. 31, 2012 DRPlus [Member]	Dec. 31, 2012 Ameren Illinois Company [Member]	Dec. 31, 2012 Ameren Missouri and Ameren Illinois [Member]	Nov. 30, 2012 Series1992 B 6.20% Due 2012 [Member] Ameren Illinois Company [Member] Environmental Improvement And Pollution Control Revenue Bonds [Member]	Dec. 31, 2012 Series1992 B 6.20% Due 2012 [Member] Ameren Illinois Company [Member] Environmental Improvement And Pollution Control Revenue Bonds [Member]		Dec. 31, 2011 Series1992 B 6.20% Due 2012 [Member] Ameren Illinois Company [Member] Environmental Improvement And Pollution Control Revenue Bonds [Member]	Aug. 20, 2012 Senior Secured Notes, 2 Point 70, Due 2022 [Member] Ameren Illinois Company [Member] Secured Debt [Member]	Dec. 31, 2012 Senior Secured Notes, 2 Point 70, Due 2022 [Member] Ameren Illinois Company [Member] Secured Debt [Member]		Dec. 31, 2011 Senior Secured Notes, 2 Point 70, Due 2022 [Member] Ameren Illinois Company [Member] Secured Debt [Member]		Sep. 11, 2012 3.90% Senior secured notes due 2042 [Member] Union Electric Company [Member] Secured Debt [Member]	Dec. 31, 2012 3.90% Senior secured notes due 2042 [Member] Union Electric Company [Member] Secured Debt [Member]		Sep. 20, 2012 3.90% Senior secured notes due 2042 [Member] Union Electric Company [Member] Secured Debt [Member]	Dec. 31, 2011 3.90% Senior secured notes due 2042 [Member] Union Electric Company [Member] Secured Debt [Member]		Sep. 20, 2012 5.25% Senior secured notes due 2012 [Member] Union Electric Company [Member] Secured Debt [Member]	Dec. 31, 2012 5.25% Senior secured notes due 2012 [Member] Union Electric Company [Member] Secured Debt [Member]		Dec. 31, 2011 5.25% Senior secured notes due 2012 [Member] Union Electric Company [Member] Secured Debt [Member]		Aug. 27, 2012 Series A 2000 5.50% Due 2014 [Member] Ameren Illinois Company [Member] Environmental Improvement And Pollution Control Revenue Bonds [Member]	Dec. 31, 2012 Series A 2000 5.50% Due 2014 [Member] Ameren Illinois Company [Member] Environmental Improvement And Pollution Control Revenue Bonds [Member]	Dec. 31, 2011 Series A 2000 5.50% Due 2014 [Member] Ameren Illinois Company [Member] Environmental Improvement And Pollution Control Revenue Bonds [Member]	Dec. 31, 2012 Minimum [Member] Ameren Illinois Company [Member]
Long-Term Debt And Equity Financings [Line Items]
Preferred stock, authorized	100,000,000
Preferred stock, par value	$ 0.01
Preferred stock, shares outstanding	0
Common stock, shares authorized	400,000,000	400,000,000				6,000,000
Common stock, shares issued		2,200,000	3,000,000	2,200,000	3,000,000
Common stock, value of shares issued		$ 65,000,000	$ 80,000,000	$ 65,000,000	$ 80,000,000
Debt instrument face amount											[1]	1,000,000	400,000,000	400,000,000	[2],[3]		[2],[3]	485,000,000	485,000,000	[4],[5]	485,000,000	0	[4],[5]		0	[5]	173,000,000	[5]			51,000,000
Stated interest rate on debt instrument									6.20%	6.20%			2.70%	2.70%				3.90%	3.90%		3.90%			5.25%	5.25%				5.50%	5.50%
Proceeds from issuance of secured debt													397,000,000					478,000,000
Repayments of long-term debt									1,000,000															173,000,000					51,000,000
Bonds interest rate assumption								6.00%
Dividend rate on preferred shares, percentage								7.00%
Excess in indebtedness upon default of maturity	$ 25,000,000
Common stock equity to capitalization ratio							57.00%																									30.00%

[1] 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.

[2] 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.

[3] 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.

[4] 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.

[5] 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.

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Nuclear Decommissioning Trust Fund Investments (Costs And Fair Values Of Investments In Debt Securities In Nuclear Decommissioning Trust Fund According To Contractual Maturities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Investments, Debt and Equity Securities [Abstract]
Cost, Less than 5 years	$ 78
Cost, 5 years to 10 years	32
Cost, Due after 10 years	23
Cost, Total	133
Fair Value, Less than 5 years	79
Fair Value, 5 years to 10 years	35
Fair Value, Due after 10 years	27
Fair Value, Total	$ 141