Exhibit 99.2 Item 7 MD&A

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

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

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

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;


•	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.

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



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



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	)

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

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

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

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.

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.

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.

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.

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.

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

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.

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.

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

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

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

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

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 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

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.



	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

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

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.

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

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

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

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.

•

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

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.

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.

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.

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.

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.

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



	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		)



	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



	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)	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.


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


(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.


(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.


•	Regulatory environment and external regulatory decisions and requirements


•	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.


•	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


•	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.


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


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


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


•	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


•	Outcome of legal proceedings, settlements or other factors


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


•	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