Illinois Power Generating 10-Q 2013 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(X)	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Quarterly Period Ended March 31, 2013
	OR
(   )	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from           to

Commission File Number 333-56594

AMEREN ENERGY GENERATING COMPANY

(Exact name of registrant as specified in its charter)

Illinois	37-1395586
(State of incorporation)	(I.R.S. Employer Identification No.)

1500 Eastport Plaza Drive, Collinsville, Illinois 62234

(Address of principal executive offices and Zip Code)

Registrant’s telephone number, including area code: (618) 343-7705

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

Yes ( ) No (X)

The registrant is not required to file reports under the Securities Exchange Act of 1934. However, the registrant has filed all Exchange Act reports for the preceding 12 months.

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

Yes (X) No ( )

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

Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer	Smaller Reporting Company
( )	( )	(X)	( )

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

Yes ( ) No (X)

As of April 30, 2013, there were 2,000 outstanding shares of common stock, without par value, of the registrant, all of which were owned by the registrant’s parent, Ameren Energy Resources Company, LLC, a subsidiary of Ameren Corporation.

OMISSION OF CERTAIN INFORMATION

The registrant meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

TABLE OF CONTENTS

		Page
Glossary of Terms and Abbreviations		1
Forward-looking Statements		1
PART I Financial Information
Item 1.	Financial Statements (Unaudited)	3
	Consolidated Statement of Income (Loss) and Comprehensive Income (Loss)	3
	Consolidated Balance Sheet	4
	Consolidated Statement of Cash Flows	5
	Notes to Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 4.	Controls and Procedures	32
PART II Other Information
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 6.	Exhibits	33
Signatures		35

This report contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors included on pages 1 and 2 of this report under the heading “Forward-looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.

GLOSSARY OF TERMS AND ABBREVIATIONS

The words “our,” “we” or “us” as used herein, refer to Genco. When appropriate, subsidiaries of Genco are named specifically as their various business activities are discussed. Refer to the Form 10-K for a complete listing of glossary terms and abbreviations. Only new or significantly changed terms and abbreviations are included below.

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

Dynegy - Dynegy, Inc.

Form 10-K - The Annual Report on Form 10-K for the year ended December 31, 2012, filed by Genco with the SEC.

Medina Valley - AmerenEnergy Medina Valley Cogen LLC, an AER subsidiary through March 13, 2013, which owned a 40-megawatt natural gas-fired electric energy center that was sold in February 2012. This company was distributed from AER to Ameren on March 14, 2013.

MISO - In April 2013, Midwest Independent Transmission System Operator, Inc. changed its name to Midcontinent Independent System Operator, Inc.

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

FORWARD-LOOKING STATEMENTS

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

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

• regulatory approvals, including from the FERC, the FCC and the Illinois Pollution Control Board relating to, and the satisfaction or waiver of the conditions to, the divestiture of New AER and regulatory approvals from FERC with respect

to the sale of the Elgin, Gibson City and Grand Tower gas-fired energy centers;

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

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

• changes in laws or regulations that adversely affect the ability of electric distribution companies and other purchasers of wholesale electricity to pay their suppliers, including Marketing Company;

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

• increasing capital expenditure and operating expense requirements and our ability to recover these costs in deregulated power markets;

• the cost and availability of fuel such as coal and natural gas used to produce electricity;

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

• the level and volatility of future prices for power in the Midwest, which may have a significant effect on our financial condition;

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

• our access to necessary capital, including short-term credit and liquidity;

• our assessment of our liquidity, including restrictions on borrowing additional funds from third-party financing sources;

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

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

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

• the impact of system outages;

• the effects of strategic initiatives, acquisitions and divestitures, including Ameren’s divestiture of New AER, including certain of our assets and liabilities, and our sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers, and any related tax implications;

• impacts under our PSA agreement with Marketing Company caused by our sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers which may impact our reimbursable costs, generation levels, and Marketing Company’s total revenues to allocate to us and AERG;

• impairments of long-lived assets and any disposal related losses;

• the impact of current environmental regulations on power generating companies and new, more stringent or changing requirements, including those related to greenhouse gases, other emissions and discharges, cooling water intake structures, CCR, and energy efficiency, that are enacted over time and that could limit or terminate the operation of

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certain of our energy centers, increase our costs, result in an impairment of our assets, reduce our customers’ demand for electricity or otherwise have a negative financial effect;

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

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

• the cost and availability of transmission capacity for the energy generated by our energy centers;

• legal and administrative proceedings; and

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

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

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

(Unaudited) (In millions)

	Three months ended March 31,
	2013			2012
Operating Revenues (Note 3)
Electric	$	185		$	194
Other	2			—
Total operating revenues	187			194
Operating Expenses:
Fuel	123			105
Other operations and maintenance	31			47
Asset impairment	207			—
Depreciation and amortization	24			23
Taxes other than income taxes	6			6
Total operating expenses	391			181
Operating Income (Loss)	(204		)	13
Interest Charges	11			14
Loss Before Income Taxes (Benefit)	(215		)	(1		)
Income Taxes (Benefit)	(86		)	2
Net Loss	(129		)	(3		)
Less: Net Loss Attributable to Noncontrolling Interest	—			(2		)
Net Loss Attributable to Ameren Energy Generating Company	$	(129	)	$	(1	)
Net Loss	$	(129	)	$	(3	)
Other Comprehensive Income, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $- and $-, respectively	1			1
Total other comprehensive income, net of taxes	1			1
Comprehensive Loss	(128		)	(2		)
Less: Comprehensive Income (Loss) Attributable to Noncontrolling Interest	—			(2		)
Comprehensive Loss Attributable to Ameren Energy Generating Company	$	(128	)	$	—

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

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AMEREN ENERGY GENERATING COMPANY CONSOLIDATED BALANCE SHEET (Unaudited) (In millions, except shares)
	March 31,			December 31,
	2013			2012
ASSETS
Current Assets:
Cash and cash equivalents	$	25		$	25
Advances to money pool	154			27
Accounts receivable – affiliates	71			70
Miscellaneous accounts receivable	14			20
Materials and supplies	73			85
Other current assets	16			28
Current assets held for sale	165			364
Total current assets	518			619
Property and Plant, Net	1,886			1,887
Other Assets	24			26
TOTAL ASSETS	$	2,428		$	2,532
LIABILITIES AND EQUITY
Current Liabilities:
Accounts and wages payable	$	45		$	54
Accounts payable – affiliates	10			12
Deposit received from affiliate for pending asset sale	100			—
Current portion of tax payable – Ameren Illinois	6			6
Taxes accrued	17			14
Interest accrued	27			12
Mark-to-market derivative liabilities	6			8
Current accumulated deferred income taxes, net	28			—
Other current liabilities	8			9
Current liabilities held for sale	31			25
Total current liabilities	278			140
Long-term Debt, Net	824			824
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	217			334
Accumulated deferred investment tax credits	2			2
Tax payable – Ameren Illinois	38			39
Asset retirement obligations	66			59
Pension and other postretirement benefits	91			92
Other deferred credits and liabilities	12			14
Total deferred credits and other liabilities	426			540
Commitments and Contingencies (Notes 2, 3 and 8)
Ameren Energy Generating Company Stockholder’s Equity:
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding	—			—
Other paid-in capital	656			656
Retained earnings	275			404
Accumulated other comprehensive loss	(39		)	(40		)
Total Ameren Energy Generating Company stockholder’s equity	892			1,020
Noncontrolling Interest	8			8
Total equity	900			1,028
TOTAL LIABILITIES AND EQUITY	$	2,428		$	2,532

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

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AMEREN ENERGY GENERATING COMPANY CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) (In millions)
	Three months ended March 31,
	2013			2012
Cash Flows From Operating Activities:
Net loss	$	(129	)	$	(3	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss on asset impairment	207			—
Net gain on sale of properties	(1		)	—
Net mark-to-market gain on derivatives	(6		)	(1		)
Depreciation and amortization	24			23
Amortization of debt issuance costs and premium/discounts	—			1
Deferred income taxes and investment tax credits, net	(79		)	(7		)
Other	—			5
Changes in assets and liabilities:
Receivables	6			27
Materials and supplies	17			(1		)
Accounts and wages payable	(16		)	(9		)
Taxes accrued	3			1
Assets, other	2			(4		)
Liabilities, other	11			13
Pension and other postretirement benefits	—			1
Net cash provided by operating activities	39			46
Cash Flows From Investing Activities:
Capital expenditures	(12		)	(33		)
Deposit received from affiliate for pending asset sale	100			—
Money pool advances, net	(127		)	(21		)
Net cash used in investing activities	(39		)	(54		)
Cash Flows From Financing Activities:
Net cash provided by financing activities	—			—
Net change in cash and cash equivalents	—			(8		)
Cash and cash equivalents at beginning of year	25			8
Cash and cash equivalents at end of period	$	25		$	—

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

March 31, 2013

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

We are a non-rate-regulated electric generation subsidiary of AER, which is a subsidiary of Ameren Corporation. 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.

We are headquartered in Collinsville, Illinois and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois. Much of our business was formerly owned and operated by CIPS. In 2000, we acquired from CIPS, at net book value, its coal-fired energy centers. Since then, we have constructed or purchased from other affiliates natural gas-fired energy centers. We have an 80% ownership interest in EEI that AER transferred to us in 2010, at net book value. We consolidate EEI for financial reporting purposes. EEI operates merchant electric generation facilities and FERC regulated transmission facilities in Illinois. We also consolidate our wholly owned subsidiary, Coffeen and Western Railroad Company, for financial reporting purposes. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

In December 2012, Ameren determined that it intended to, and it was probable that it would, exit its merchant generation business, of which we are a part. Based on the expectation of reduced financial support from Ameren, together with existing power market conditions and cash flow requirements, we estimated, at that time, it was more likely than not that we would sell our Elgin energy center for liquidity purposes within two years. This change in assumption resulted in a noncash long-lived asset impairment in the fourth quarter of 2012 relating to the Elgin energy center. Our long-lived assets were not classified as held-for-sale as of December 31, 2012, under authoritative accounting guidance as all criteria to qualify for that presentation were not met as of December 31, 2012. Specifically, AER did not consider it probable at December 31, 2012, that a disposition of an energy center would occur within one year.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Immediately prior to Ameren’s entry into the transaction agreement with IPH, on March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. Ameren has commenced a sale process for these three gas-fired energy centers and expects a third-party sale to be completed during 2013. See Note 2 - Assets Held for Sale for additional information. We

determined, as of March 31, 2013, that the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for held for sale presentation; therefore, we have segregated the assets and liabilities associated with these gas-fired energy centers and presented them separately as held for sale as of March 31, 2013, and comparatively at December 31, 2012. The operating results of the Elgin, Gibson City, and Grand Tower gas-fired energy centers did not qualify for discontinued operations presentation because we will continue to sell power into the same markets with our remaining generation assets. See Note 2 - Assets Held for Sale for additional information regarding that presentation.

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

Uncertain Tax Positions

The amount of unrecognized tax benefits as of March 31, 2013, was $7 million. The amount of unrecognized tax benefits as of March 31, 2013, would have no impact on the effective tax rate, if recognized.

We are included in Ameren’s federal income tax return. Ameren’s federal income tax returns for the years 2007 through 2010 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2011 is currently under examination.

It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the next 12 months for the years 2007 through 2010. This settlement, primarily related to uncertain tax positions for capitalization versus currently deductible repair expense and research tax deductions, is expected to result in a decrease in uncertain tax benefits of $7 million. In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits to increase or decrease. However, we do not believe any such increases or decreases, including the decrease from the reasonably possible IRS Appeals Office settlement discussed above, would be material to our results of operations, financial position, or liquidity.

State income tax returns are generally subject to examination for a period of three years after filing of the return. We do not currently have material state income tax issues under examination, administrative appeals, or litigation. The state

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impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states.

Noncontrolling Interest

Noncontrolling interest comprised the 20% of EEI we do not own. This noncontrolling interest is classified as a component of equity separate from our equity in the consolidated balance sheet. Net income attributable to noncontrolling interest during the first quarter of 2013 was less than $1 million. The balance of the noncontrolling interest on our balance sheet changed by less than $1 million for the three months ended March 31, 2013.

Asset Retirement Obligations

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the three months ended March 31, 2013:

Balance at December 31, 2012	$	59
Liabilities incurred	—
Liabilities settled	(a)
Accretion	1
Change in estimates(b)	6
Balance at March 31, 2013	$	66

(a) Less than $1 million.

(b) We changed our estimate related to updated retirement dates for certain CCR storage facilities.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Under the terms of that agreement, Ameren will retain the existing AROs associated with the Meredosia and Hutsonville energy centers, which were estimated at $27 million as of March 31, 2013. AROs associated with the Meredosia and Hutsonville energy centers will continue to be included in “Asset retirement obligations” on our consolidated balance sheet until they are transferred to Ameren prior to the transaction closing with IPH. The ARO associated with the Grand Tower energy center of $10 million was included in “Current liabilities held for sale” as of March 31, 2013, and December 31, 2012. After the transaction closing with IPH, we will retain the remaining AROs associated with our operations. See Note 2 - Assets Held for Sale for information regarding our sale of the Grand Tower energy center to Medina Valley and the transfer of the Meredosia and Hutsonville energy centers to Medina Valley.

Retirement Benefits

We offer defined benefit pension and postretirement benefit plans covering substantially all of our employees. Our employees and retirees, excluding EEI employees and retirees, participate in Ameren’s single-employer pension and other postretirement plans. Ameren’s qualified pension plan is the Ameren Retirement Plan. Ameren also has an unfunded non-qualified pension plan, the Ameren Supplemental Retirement Plan, which is available for certain management employees and retirees to provide a supplemental benefit when their qualified pension plan benefits are reduced to comply with Internal Revenue Code limitations. Ameren’s other postretirement plans are the Ameren Retiree Medical Plan and the Ameren Group Life Insurance Plan. Separately, our EEI employees and retirees participate in EEI’s single-employer pension and other postretirement plans. EEI’s pension plan is the Revised Retirement Plan for Employees of Electric Energy, Inc. EEI’s other postretirement plans are the Group Insurance Plan for Management Employees of Electric Energy, Inc. and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. We consolidate EEI, and therefore, EEI’s plans are reflected in our pension and postretirement balances and disclosures.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Under the terms of that agreement, Ameren will retain the portion of our pension and postretirement benefit obligations associated with current and former employees that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan. We will retain the pension and other postretirement benefit obligations associated with EEI’s current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. These EEI obligations are estimated at $39 million at March 31, 2013 and are included in “Pension and other postretirement benefits” on our consolidated balance sheet. We will also retain the $15 million asset relating to the overfunded status of one of EEI’s postretirement plans, which is included in “Other assets” on our consolidated balance sheet.

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The following table presents the components of our net periodic benefit cost of the EEI pension and postretirement benefit plans and an allocation of net periodic benefit costs from our participation in Ameren’s single-employer pension and postretirement benefit plans during three months ended March 31, 2013, and 2012:

	Pension Benefits(a)						Postretirement Benefits(a)
	Three Months						Three Months
	2013			2012			2013			2012
Service cost	$	1		$	1		$	—		$	1
Interest cost	2			3			1			2
Expected return on plan assets	(3		)	(3		)	(1		)	(2		)
Amortization of:
Prior service cost (benefit)	—			—			(2		)	—
Actuarial loss	2			1			1			1
Net periodic benefit cost	$	2		$	2		$	(1	)	$	2

(a) Includes amounts for our participation in Ameren’s single-employer plans and the cost of EEI’s plans.

In addition to the above net period benefit cost for pension benefits, we were allocated less than $1 million in net periodic benefit costs from Ameren Services employees doing work on our behalf during the three months ended March 31, 2013, and 2012. We were also allocated less than $1 million in net periodic benefit costs for postretirement benefits from Ameren Services employees doing work on our behalf during the three months ended March 31, 2013, and 2012.

See Note 2 - Assets Held for Sale for additional information regarding Ameren’s retention of its single-employer pension and postretirement benefit plans.

Accounting and Reporting Developments

The following is a summary of recently adopted authoritative accounting guidance that could impact us.

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for us beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect our results of operations, financial position, or liquidity.

In February 2013, FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. This guidance was effective for us beginning in the first quarter of 2013. The implementation of this amendment did not affect our results of operations, financial position, or liquidity. The only amounts reclassified out of accumulated OCI related to pension and other postretirement plan activity. These amounts were immaterial during the first quarter of 2013 and 2012, and, therefore, no additional disclosures were required.

Disclosures about Offsetting Assets and Liabilities

In December 2011, FASB issued additional authoritative accounting guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The amendments did not affect our results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. We adopted this guidance for the first quarter of 2013. See Note 6 - Derivative Financial Instruments for the required additional disclosures.

NOTE 2 - ASSETS HELD FOR SALE

Transaction Agreement with IPH

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

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New AER. IPH will acquire all of the equity interests in New AER. On March 13, 2013, AER transferred its interest in Medina Valley at carrying value to Ameren.

Ameren will retain the portion of our pension and postretirement benefit obligations associated with current and former employees that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan. We will retain the pension and other postretirement benefit obligations associated with EEI’s current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. These EEI obligations are estimated at $39 million at March 31, 2013. We will also retain the estimated $15 million asset at March 31, 2013, relating to the overfunded status of one of EEI’s postretirement plans.

Ameren will retain our Meredosia and Hutsonville energy centers, which are no longer in operation and had an immaterial property and plant asset balance as of March 31, 2013. Ameren will also retain AROs associated with these energy centers, estimated at $27 million as of March 31, 2013. Upon the transaction agreement closing, with the exception of certain agreements, such as our money pool advances, all intercompany agreements and debt between AER and its subsidiaries, on the one hand, and Ameren and its affiliates, on the other hand, will be either retained or cancelled by Ameren, without any cost or obligation to IPH or New AER and its subsidiaries. Ameren will retain our tax payable to Ameren Illinois, which was $44 million as of March 31, 2013.

Ameren’s retention of our liabilities for pension and postretirement benefit obligations relating to Ameren’s plans, the Meredosia and Hutsonville energy centers and those two energy centers’ related AROs, the tax payable to Ameren Illinois, and related deferred tax balances associated with each transferred balance will be accounted for as transactions between entities under common control and transferred at their carrying values.

In addition, if this transaction with IPH is completed, we expect the tax basis of our property, plant and equipment to decrease and our deferred tax assets related to federal and state income tax net operating loss carryforwards and income tax credits to decrease with corresponding offsets to equity. The amount of any such decrease is dependent on the value and timing of the New AER divestiture transaction.

As described in more detail below under “Amended Put Option Agreement, Asset Purchase Agreement and Guaranty”, as a condition to the transaction agreement, we will receive cash proceeds from the exercise of our option under the March 28, 2012 put option agreement, as amended, for the sale to Medina Valley of the Elgin, Gibson City and Grand Tower gas-fired energy centers in an amount equal to the greater of $133 million or the appraised value of such energy centers. If these gas-fired energy centers are subsequently sold by Medina Valley within

two years of the put option closing, Medina Valley will pay us any proceeds from such sale, net of taxes and other expenses, in excess of the amount it paid at the asset purchase agreement closing. Ameren has commenced a sale process for these energy centers and expects a third-party sale will be completed during 2013.

Our $825 million of senior notes will remain outstanding following the transaction agreement closing and will continue to be solely our obligation. Pursuant to the transaction agreement, in addition to the cash we receive for the Elgin, Gibson City, and Grand Tower energy center sale, we will retain cash of $70 million at closing.

Completion of the New AER sale to IPH is subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC. On April 16, 2013, AER and Dynegy filed with FERC an application for approval of the divestiture of New AER and our sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. As a condition to IPH’s obligation to complete the transaction, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS. AER and Dynegy filed a transfer request with the Illinois Pollution Control Board on May 2, 2013. Ameren’s and IPH’s obligation to complete the transaction is also subject to other customary closing conditions, including the material accuracy of each company’s representations and warranties and the compliance, in all material respects, with each company’s covenants. The transaction agreement contains customary representations and warranties of Ameren and IPH, including representations and warranties of Ameren with respect to the business being sold. The transaction agreement also contains customary covenants of Ameren and IPH, including the covenant of Ameren that AER will be operated in the ordinary course prior to the closing.

Ameren expects the closing of the New AER divestiture to IPH will occur in the fourth quarter of 2013. If the closing does not occur on or before March 14, 2014, subject to a one-month extension to obtain FERC approval, either party may elect to terminate the transaction agreement if the inability to close the transaction by such date is not the result of the failure of the terminating company to fulfill any of its obligations under the transaction agreement.

Amended Put Option Agreement, Asset Purchase Agreement and Guaranty

On March 28, 2012, we entered into a put option agreement with AERG, which gave us the option to sell to AERG all, but not less than all, of the Elgin, Gibson City and Grand Tower gas-fired energy centers.

Prior to Ameren’s entry into the transaction agreement with IPH as discussed above, (i) our original put option agreement with AERG was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley and (ii) we exercised our option under the amended put option agreement to sell the Elgin, Gibson City and Grand Tower gas-fired energy centers to Medina Valley. As a

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result, on March 14, 2013, Medina Valley paid us an initial payment of $100 million, with an offset to “Deposit received from affiliate for pending asset sale,” in accordance with the terms of the amended put option agreement, asset purchase agreement, and transaction agreement with IPH. That deposit will remain on our balance sheet until the assets and liabilities are transferred to Medina Valley. We advanced the initial payment amount we received to the non-state-regulated subsidiary money pool. In connection with the amended put option agreement, Ameren's guaranty, dated March 28, 2012, was modified to replace all references to AERG with references to Medina Valley.

Pursuant to the amended put option agreement, we entered into an asset purchase agreement with Medina Valley. We have engaged three appraisers to conduct a fair market valuation of the Elgin, Gibson City and Grand Tower gas-fired energy centers, whose valuations will be averaged and subject to adjustment at the closing of the asset purchase agreement to reflect the assets and liabilities associated with the Elgin, Gibson City and Grand Tower gas-fired energy centers. At the asset purchase agreement closing, we will receive an additional amount equal to the greater of (i) $33 million, or (ii) the appraised value of the Elgin, Gibson City and Grand Tower gas-fired energy centers less the initial

payment of $100 million, for a total purchase price of at least $133 million, and we will sell and transfer to Medina Valley all of its rights in the Elgin, Gibson City and Grand Tower gas-fired energy centers as a condition to the transaction agreement with IPH. If these gas-fired energy centers are subsequently sold by Medina Valley within two years of the asset purchase agreement closing, Medina Valley will pay us any proceeds from such sale, net of taxes and other expenses, in excess of the amounts previously paid to us. Ameren has commenced a sale process for these three energy centers and expects a third-party sale will be completed during 2013. Should FERC approval not be obtained and the transfer of the Elgin, Gibson City, and Grand Tower energy centers cannot be completed, we will be required to return to Medina Valley the initial payment we received in March 2013.

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

We determined that the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for held for sale presentation as of March 31, 2013. As of December 31, 2012, these energy centers did not meet the criteria to be classified as held for sale as it was not probable at that time that they would be disposed of within one year. To enhance the comparability of these quarterly financial statements, we have recast our December 31, 2012 balance sheet to reflect the presentation of the Elgin, Gibson City, and Grand Tower energy centers as held for sale at that date. The following table presents the components of assets and liabilities held for sale on our consolidated balance sheet at March 31, 2013, and December 31, 2012:

	March 31, 2013		December 31, 2012
Current assets held for sale
Materials and supplies	$	6	$	12
Mark-to-market derivative assets	19		4
Property and plant, net	138		348
Other assets	2		—
Total current assets held for sale	$	165	$	364
Current liabilities held for sale
Accounts and wages payable	$	3	$	9
Taxes accrued	3		3
Mark-to-market derivative liabilities	15		3
Asset retirement obligations	10		10
Total current liabilities held for sale	$	31	$	25

As the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers met the held for sale criteria at March 31, 2013, we evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value less cost to sell. The estimated fair value was determined by reference to the amended put option agreement, the asset purchase agreement with Medina Valley, and the transaction agreement with IPH, which we believe approximates fair value. As a result, we recorded a pretax charge to earnings of $207 million for the three months ended March 31, 2013, to reflect the impairment of the

Elgin, Gibson City and Grand Tower gas-fired energy centers. The impairment recorded during the first quarter of 2013 primarily related to the Gibson City and Grand Tower energy centers as the Elgin energy center was previously impaired under held and used accounting guidance during the fourth quarter of 2012. This first quarter of 2013 charge to earnings was recorded as an impairment of “Property and Plant, net” within the components of current assets held for sale shown above and “Asset impairment” in our consolidated statement of income (loss) and comprehensive income (loss). During the three months ended March 31, 2013, we recorded an $81 million income tax benefit as a result of the impairment.

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These assets and liabilities were measured at fair value on a nonrecurring basis with inputs that are classified as Level 3 within the fair value hierarchy.

Effective with our conclusion in March 2013 that the Elgin, Gibson City, and Grand Tower gas-fired energy centers met the criteria for held for sale presentation, we suspended recording depreciation on these energy centers.

NOTE 3 – RELATED PARTY TRANSACTIONS

We have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. For a discussion of our material related party

agreements, see Note 2 - Related Party Transactions under Part II, Item 8, of the Form 10-K.

Employee Transfer

Through the end of 2012, some Ameren Services employees were included within AER's business services group, which provides back office, controller, pricing, analytical support, engineering services, and selected information technology services for AER and its subsidiaries. On December 31, 2012, 74 of these employees were transferred from Ameren Services to us through an internal reorganization. These employees continue to provide support services to AER subsidiaries.

Money Pools

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

The following table presents the impact of related party transactions for the three months ended March 31, 2013, and 2012. It is based primarily on the agreements discussed above and in Note 2 - Related Party Transactions under Part II, Item 8, of the Form 10-K, and the money pool arrangements discussed in Note 4 - Short-term Debt and Liquidityof this report.

			Three Months
Agreement	Income Statement Line Item		2013		2012
Genco and EEI power supply agreements with Marketing Company	Operating Revenues - Electric	$	185	$	192
Natural gas sales to Medina Valley(a)	Operating Revenues - Electric		—		1
Services provided to AER affiliates	Operating Revenues - Other		2		—
Total Operating Revenues		$	187	$	193
Ameren Missouri gas transportation agreement	Fuel	$	(b)	$	(b)
EEI power supply agreement with Marketing Company	Purchased Power	$	(b)	$	(b)
Ameren Services support services agreement	Other Operations and Maintenance	$	3	$	5
Money pool borrowings (advances)	Interest (Charges) Income	$	(b)	$	(b)

(a) Natural gas sold at fair value.

(b) Amount less than $1 million.

NOTE 4 - SHORT-TERM DEBT AND LIQUIDITY

On November 14, 2012, the 2010 Genco Credit Agreement was terminated and not renewed. Should a financing need arise, 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, we amended and exercised our option to sell our three natural gas-fired energy centers to Medina Valley for a sales price of at least $133 million. In March 2013, we received an initial payment of $100 million for the pending sale of our Elgin, Gibson City and Grand Tower gas-fired energy centers to Medina Valley. We advanced the initial payment amount we received to the non-state-regulated subsidiary money pool. With the additional liquidity received through exercising the amended put option agreement, our financing sources are estimated to be adequate to support our operations in 2013. See Note 2 - Assets Held for Sale for additional information regarding the amended put option agreement.

Money Pool

Ameren established a non-state regulated subsidiary money pool to coordinate and to provide short-term cash and working capital to its non-state regulated subsidiaries. We have the ability, subject to Ameren parent company authorization, to access funding from Ameren and Ameren Missouri's $1.0 billion multiyear senior unsecured credit agreement, Ameren and Ameren Illinois' $1.1 billion multiyear senior unsecured credit agreement, and Ameren's commercial paper programs through a money pool agreement. We may borrow from or lend to the non-state regulated subsidiary money pool. When receiving a loan under that money pool agreement, we must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state regulated subsidiary money pool. The average interest rate for borrowings under the non-state regulated subsidiary money pool for the three months ended March 31, 2013, was 0.22% (2012 – 0.76%).

See Note 3 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements for the first three months of 2013 and 2012.

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NOTE 5 – LONG-TERM DEBT

Indenture Provisions and Other Covenants

We 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.

Our indenture includes provisions that require us to maintain certain interest coverage and debt-to-capital ratios in order for us to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these ratios for the three months ended and as of March 31, 2013:

	Required Ratio	Actual Ratio
Restricted payment interest coverage ratio(a)	≥1.75	2.3
Additional indebtedness interest coverage ratio(b)	≥2.50	2.3
Additional indebtedness debt-to-capital ratio(b)	≤60%	50	%

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

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

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

As shown in the table above, under the provisions of our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is less than a specified minimum or if our debt-to-capital ratio is greater than a specified maximum. During the first quarter of 2013, our interest coverage ratio fell to a level less than the specified minimum level required for external borrowings, and we expect the ratio to remain less than this minimum level through at least 2015. As a result, our ability to borrow additional funds from external, third-party sources is restricted. Our indenture does not restrict intercompany borrowings from Ameren's non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren's control. If an intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool would be dependent on consideration by

Ameren of the facts and circumstances existing at that time. We will seek to fund operations internally and therefore seek not to rely on financing from Ameren. Ameren’s transaction agreement with IPH requires Ameren to operate AER in the ordinary course prior to the closing.

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

Our indenture includes restrictions that prohibit payments of dividends on our common stock. Specifically, dividends cannot be paid unless the 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 March 31, 2013, of operating results and cash flows in 2013 and 2014, we do not believe that we would achieve the minimum interest coverage ratio necessary to pay dividends on our common stock for each of the subsequent four six-month periods ending September 30, 2013, March 31, 2014, September 30, 2014, or March 31, 2015. As a result, we were restricted from paying dividends as of March 31, 2013, and we expect to be unable to pay dividends on our common stock through at least March 31, 2016.

Off-Balance-Sheet Arrangements

At March 31, 2013, we had no off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. We do not expect to engage in any significant off-balance-sheet financing arrangements in the near future.

NOTE 6 – DERIVATIVE FINANCIAL INSTRUMENTS

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

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

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

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

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

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The following table presents open gross commodity contract volumes by commodity type as of March 31, 2013, and December 31, 2012:

	Quantity (in millions)
Commodity	Accrual & NPNS Contracts(a)		Other Derivatives(b)
	2013	2012	2013	2012
Coal (in tons)	26	30	5	5
Fuel oils (in gallons)(d)	(c)	(c)	35	40
Natural gas (in mmbtu)(e)	(c)	(c)	90	42
Power	(f)	(f)	—	—

(a) Accrual contracts include commodity contracts that do not qualify as derivatives. Contracts through December 2017 for coal as of March 31, 2013.

(b) As of March 31, 2013, contracts through December 2015, October 2016, and April 2015 for coal, fuel oils, and natural gas, respectively.

(c) Not applicable.

(d) Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.

(e) Amounts include commodity contracts classified as held for sale.

(f) See Note 2 - Related Party Transactions under Part II, Item 8, of the Form 10-K for the annual amount of physical gigawatthour sales under Genco’s related party electric PSA with Marketing Company, including EEI’s PSA with Marketing Company.

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

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

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

Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under

the same master netting arrangement. We did not elect to adopt this guidance for any eligible commodity contracts.

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

	Balance Sheet Location	2013		2012
Derivative assets not designated as hedging instruments
Commodity contracts:
Coal	Other current assets	$	1	$	—
	Other assets	—		1
Fuel oils	Other current assets	2		2
	Other assets	1		1
Natural gas	Current assets held for sale	19		4
	Total assets	$	23	$	8
Derivative liabilities not designated as hedging instruments
Commodity contracts:
Coal	MTM derivative liabilities	$	5	$	7
	Other deferred credits and liabilities	3		3
Fuel oils	MTM derivative liabilities	1		1
	Other deferred credits and liabilities	—		1
Natural gas	Current liabilities held for sale	15		3
	Total liabilities	$	24	$	15

The cumulative amount of pretax net losses on interest rate derivative instruments in accumulated OCI was $7 million and $7 million, respectively, as of March 31, 2013 and December 31, 2012. These interest rate swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with our April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. Over the next 12 months, $1.4 million of the loss will be amortized.

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

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

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These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions.

Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

Although we had not previously elected to offset fair value amounts and collateral for derivative instruments executed with the same counterparty under the same master netting arrangement, authoritative accounting guidance, effective in the first quarter 2013, requires those amounts eligible to be offset to be presented both at the gross and net amounts. The following table provides the recognized gross derivative balances and the net amounts of those derivatives subject to an enforceable master netting arrangement or similar agreement as of March 31, 2013, and December 31, 2012:

			Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Amounts Recognized in the Consolidated Balance Sheet		Derivative Instruments		Cash Collateral Received/Posted(a)		Net Amount
2013
Assets:
Commodity contracts eligible to be offset(b)	$	23	$	17	$	—	$	6
Liabilities:
Commodity contracts eligible to be offset(b)	$	24	$	17	$	—	$	7
2012
Assets:
Commodity contracts eligible to be offset(b)	$	8	$	5	$	—	$	3
Liabilities:
Commodity contracts eligible to be offset(b)	$	15	$	5	$	—	$	10

(a) Cash collateral received reduces gross asset balances and cash collateral posted reduces gross liability balances.

(b) Includes amounts classified as held for sale.

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of March 31, 2013, and December 31, 2012, if counterparty groups were to fail completely to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including accrual and NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.

	Coal Producers		Commodity Marketing Companies		Financial Companies		Oil and Gas Companies		Total
2013(a)	$	—	$	1	$	2	$	3	$	6
2012(a)	$	2	$	1	$	2	$	2	$	7

(a) Includes amounts classified as held for sale.

The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held. As of March 31, 2013 and December 31, 2012, we held no collateral to reduce exposure. The following table presents the potential loss after consideration of the application of master trading and netting agreements as of March 31, 2013, and December 31, 2012:

	Coal Producers		Commodity Marketing Companies		Financial Companies		Oil and Gas Companies		Total
2013(a)	$	—	$	—	$	2	$	2	$	4
2012(a)	$	1	$	—	$	1	$	—	$	2

(a) Includes amounts classified as held for sale.

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to our credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of March 31, 2013, and December 31, 2012, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral

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posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements assuming (1) the credit risk-related contingent features underlying these agreements were triggered on March 31, 2013, or December 31, 2012, respectively, and (2) those counterparties with rights to do so requested collateral:

	Aggregate Fair Value of Derivative Liabilities(a)		Cash Collateral Posted		Potential Aggregate Amount of Additional Collateral Required(b)
2013(c)	$	44	$	—	$	40
2012(c)	$	48	$	—	$	31

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

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

(c) Includes amounts classified as held for sale.

Cash Flow Hedges

The following table presents the pretax net gain or loss for the three months ended March 31, 2013, and 2012, associated with derivative instruments designated as cash flow hedges:

		Gain (Loss) Recognized in OCI(a)	Location of (Gain) Loss Reclassified from Accumulated OCI into Income(b)		(Gain) Loss Reclassified from Accumulated OCI into Income(b)	Location of Gain (Loss) Recognized in Income(c)		Gain (Loss) Recognized in Income(c)
2013
Interest rate(d)	$	—	Interest Charges	$	(e)	Interest Charges	$	—
2012
Interest rate(d)	$	—	Interest Charges	$	(e)	Interest Charges	$	—

(a) Effective portion of gain (loss).

(b) Effective portion of (gain) loss on settlements.

(c) Ineffective portion of gain (loss) and amount excluded from effectiveness testing.

(d) Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.

(e) Less than $1 million.

Other Derivatives

The following table represents the net change in market value associated with derivatives not designated as hedging instruments for the three months ended March 31, 2013, and 2012:

	Location of Gain (Loss) Recognized in Income	Gain (Loss) Recognized in Income
		2013		2012
Coal	Operating Expenses - Fuel	$	2	$	(3	)
Fuel oils	Operating Expenses - Fuel	1		4
Natural gas(a)	Operating Expenses - Fuel	3		—
	Total	$	6	$	1

(a) Includes amounts classified as held for sale.

NOTE 7 – FAIR VALUE MEASUREMENTS

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation

techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives.

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

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and liabilities include certain over-the-counter derivative instruments, including natural gas swaps. Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint.

Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use

significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our fair value estimation process, an evaluation of all sources is performed to identify any anomalies or potential errors.

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

The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2013:

	Fair Value							Weighted
	Assets		Liabilities		Valuation Technique(s)	Unobservable Input	Range	Average
Level 3 Derivative asset and liability - commodity contracts(a):
Fuel oils	$	1	$	—	Discounted cash flow	Escalation rate(%)(b)	.20 - .71	.55
						Counterparty credit risk(%)(c)(d)	.26 - 1	1
						Genco credit risk(%)(c)(d)	3 - 29	20
					Option model	Volatilities(%)(b)	14 - 19	18

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

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

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

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

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

	Fair Value							Weighted
	Assets		Liabilities		Valuation Technique(s)	Unobservable Input	Range	Average
Level 3 Derivative asset and liability - commodity contracts(a):
Fuel oils	$	1	$	—	Discounted cash flow	Escalation rate(%)(b)	.21 - .68	.59
						Counterparty credit risk(%)(c)(d)	.12 - 1	1
						Genco credit risk(%)(c)(d)	3 - 31	24
					Option model	Volatilities(%)(b)	19 - 27	23

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

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

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

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

In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. We recorded net gains of less than $1 million and net losses of less than $1 million, for the three months ended March 31, 2013, and 2012, respectively, related to valuation adjustments for counterparty default risk. The counterparty default risk liability valuation adjustment related to derivative contracts totaled less than $1 million and less than $1 million, at March 31, 2013 and December 31, 2012, respectively.

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The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of March 31, 2013, and December 31, 2012:

		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
2013
Assets:
	Derivative assets - commodity contracts(a):
	Coal	$	1	$	—	$	—	$	1
	Fuel oils	2		—		1		3
	Natural gas	19		—		—		19
	Total assets	$	22	$	—	$	1	$	23
Liabilities:
	Derivative liabilities - commodity contracts(a):
	Coal	$	8	$	—	$	—	$	8
	Fuel oils	1		—		—		1
	Natural gas	15		—		—		15
	Total liabilities	$	24	$	—	$	—	$	24
2012
Assets:
	Derivative assets - commodity contracts(a):
	Coal	$	1	$	—	$	—	$	1
	Fuel oils	2		—		1		3
	Natural gas	4		—		—		4
	Total assets	$	7	$	—	$	1	$	8
Liabilities:
	Derivative liabilities - commodity contracts(a):
	Coal	$	10	$	—	$	—	$	10
	Fuel oils	2		—		—		2
	Natural gas	3		—		—		3
	Total liabilities	$	15	$	—	$	—	$	15

(a) The derivative asset and liability balances are presented net of counterparty credit considerations. Balances include amounts classified as held for sale.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of March 31, 2013, and 2012:

	2013		2012
Fuel oils:
Beginning balance at January 1	$	1	$	1
Realized and unrealized gains (losses):
Included in earnings(a)	—		2
Total realized and unrealized gains (losses)	—		2
Purchases	—		—
Settlements	—		—
Transfers into Level 3	—		—
Transfers out of Level 3	—		(1		)
Ending balance at March 31	$	1	$	2
Change in unrealized gains (losses) related to assets/liabilities held at March 31	$	—	$	1

(a) Net gains and losses on fuel oils derivative commodity contracts are recorded in “Operating Expenses – Fuel”.

Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Fuel oils transfers between Level 1 and Level 3 were primarily caused by changes in availability of financial trades observable on electronic exchanges from the previous reporting period for the three months ended March 31, 2013 and 2012. Any reclassifications are

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reported as transfers into or out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the three months ended March 31, 2013, and 2012, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. For the three months ended March 31, 2013, there were no transfers between Level 1 and Level 3 related to derivative commodity contracts. For the three months ended March 31, 2012, there were fuel oil transfers out of Level 3 and into Level 1 of $(1) million.

Our carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. The estimated fair value of long-term debt is based on the quoted market prices for same or similar issuances for companies with similar credit profiles, which fair value measurement is considered Level 2 in the fair value hierarchy.

The following table presents the carrying amounts and estimated fair values of our long-term debt at March 31, 2013, and December 31, 2012:

	March 31, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	824	$	629	$	824	$	618

NOTE 8 – COMMITMENTS AND CONTINGENCIES

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

See also Note 1 – Summary of Significant Accounting Policies, Note 2 - Assets Held for Sale, and Note 3 – Related Party Transactions in this report.

Other Obligations

To supply a portion of the fuel requirements of our energy centers, we have entered into various long-term commitments for the procurement of coal and natural gas. For a complete listing of our obligations and commitments, see Note 10 - Commitments and Contingencies under Part II, Item 8, of the Form 10-K.

At March 31, 2013, total other obligations related to the procurement of coal and natural gas, among other agreements, were $473 million. In addition, total unrecognized tax benefits at March 31, 2013, were $7 million.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generation and transmission facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified

facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

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

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environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.

The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations, including the CAIR, and our assessment of the potential impacts of the EPA's proposed regulation for CCR and the MATS as of March 31, 2013. In addition, the estimates assume that CCR will continue to be regarded as nonhazardous. The estimates do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures or the impact of the effluent standards applicable to steam-electric generating units that the EPA proposed in April 2013 as our evaluation of those impacts is ongoing. The estimates, shown in the table below, could change significantly depending upon a variety of factors including:

• additional or modified federal or state requirements;

• further regulation of greenhouse gas emissions;

• revisions to CAIR or reinstatement of CSAPR;

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

• additional or new rules governing air pollutant transport;

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

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

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

• new technology;

• expected power prices;

• variations in costs of material or labor; and

• alternative compliance strategies or investment decisions.

	Low			High
2013	$	30	-	$	30
2014 - 2017	100		-	125
2018 - 2022	220		-	270
Total(a)	$	350	-	$	425

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

The decision to make pollution control equipment investments depends on whether the expected future market prices for power reflects the increased cost for environmental compliance.

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

Clean Air Act

Both federal and state laws require significant reductions in SO₂ and NO_x emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO₂ and NO_x emissions (the CAIR). The CAIR required generating

facilities in 28 states, including Illinois, and the District of Columbia, to participate in cap-and-trade programs to reduce annual SO₂ emissions, annual NO_x emissions, and ozone season NO_x emissions.

In December 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the CAIR to the EPA for further action to remedy the rule's flaws, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR. In August 2012, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that vacated the CSAPR in its entirety, finding that the EPA exceeded its authority in imposing the CSAPR's emission limits on states. In January 2013, the full Court of Appeals for the District of Columbia Circuit denied the EPA's request for rehearing. In March 2013, the EPA and certain environmental groups filed an appeal of the Circuit Court’s remand of CSAPR to the Supreme Court. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the decision to vacate the CSAPR is overturned by the United States Supreme Court.

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

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

In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standards for ozone. The EPA is required to revisit these standards for ozone again in 2013. The state of Illinois will be required to develop an attainment plan to comply with the 2008 ambient air quality standards for ozone, which could result in additional emission

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control requirements for power plants by 2020. We continue to assess the impacts of these new standards.

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

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

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

As a condition to IPH’s obligation to complete the acquisition of New AER, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS. AER and Dynegy filed a transfer request with the Illinois Pollution Control Board on May 2, 2013. See Note 2 - Assets Held for Sale for additional information.

Under the MPS, AER is required to reduce mercury, NO_x and SO₂ emissions with declining limits starting in 2009 for mercury and in 2010 for NO_x and SO_2. The final NO_x limit became effective in 2012. The final mercury limit will become effective in 2015 and the final SO₂ limit will become effective by the end of 2019. The Illinois Pollution Control Board's September 2012 variance gives AER additional time for economic recovery and related power price improvements necessary to support scrubber installations and other pollution controls at some of AER's energy centers. To comply with the MPS and other air emissions laws and regulations, we are installing equipment designed to reduce our emissions of mercury, NO_x, and SO₂. We have installed two scrubbers at the Coffeen energy center. Two additional scrubbers are being constructed at the Newton energy center. We will continue to review and adjust our compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, emission standards required under environmental laws and regulations and compliance technologies, among other factors.

Environmental compliance costs could be prohibitive at some of our energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their

continued operation, which could result in the impairment of long-lived assets.

Emission Allowances

The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NO_x budget trading program, and the CAIR. Environmental regulations, including those relating to the timing of the installation of pollution control equipment, fuel mix, and the level of operations will have a significant impact on the number of allowances required for ongoing operations. The CAIR uses the acid rain program's allowances for SO₂ emissions and created annual and ozone season NO_x allowances. We expect to have adequate CAIR allowances for 2013 to avoid needing to make external purchases to comply with these programs.

Global Climate Change

State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change. Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO₂ emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO₂.

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

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA issued the “Tailoring Rule,” which established new higher emission thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permits upon renewal. Currently, our energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to address greenhouse gas emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse

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gas emissions exceed the applicable emissions threshold. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how the state of Illinois applies the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in operations subject to the rule occur at our energy centers. In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld the Tailoring Rule. Industry groups and a coalition of states filed petitions in April 2013 requesting that the United States Supreme Court review the circuit court’s decision upholding the Tailoring Rule.

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

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force us, as well as other similarly situated electric power generators, to close some coal-fired facilities earlier than planned, which could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on our results of operations, financial position, and liquidity.

Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change. In March 2012, the United States District Court for the Southern District of Mississippi dismissed the Comer v. Murphy Oil lawsuit, which alleged that CO₂ emissions from several industrial companies, including our energy centers, created atmospheric conditions that intensified Hurricane Katrina, thereby causing property damage. The case has been appealed to the appellate court.

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

for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.

NSR and Clean Air Litigation

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

Commencing in 2005, we received a series of information requests from the EPA pursuant to Section 114(a) of the Clean Air Act. The requests sought detailed operating and maintenance history data with respect to our Coffeen, Hutsonville, Meredosia, Newton, and Joppa energy centers. In August 2012, we received a Notice of Violation from the EPA alleging violations of permitting requirements including Title V of the Clean Air Act. The EPA contends that projects performed in 1997, 2006, and 2007 at our Newton energy center violated federal law. We believe our defenses to the allegations described in the Notice of Violation are meritorious. We have included $3 million in “Other current liabilities” on our consolidated balance sheet as of March 31, 2013, relating to this loss contingency. We are unable to predict the outcome of this matter and whether EPA will address this Notice of Violation administratively or through litigation.

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

Clean Water Act

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25% of that water exclusively for cooling. Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant's intake screens or to reduce intake velocity to a specified level. The proposed rule also requires existing power plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in June 2013, with compliance expected within eight years thereafter. All coal-fired and combined cycle energy centers with cooling water systems are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities, as other technology options potentially could meet the site-specific standards. We are currently evaluating the proposed rule, and our assessment of the proposed rule's impacts is ongoing. Therefore, we cannot predict at this time the capital or operating

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costs associated with compliance. The proposed rule, if adopted, could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our energy centers.

In April 2013, the EPA announced its proposal to revise the effluent limitation guidelines applicable to steam electric generating units under the Clean Water Act. Effluent limitation guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The proposed revision targets wastewater streams associated with fluegas desulfurization (i.e. scrubbers), fly ash, bottom ash, fluegas mercury control, CCR leachate from landfills and impoundments, nonchemical metal cleaning and gassification of fuels. The EPA’s proposal identifies several alternatives for addressing these waste streams, including best management practices for CCR impoundments.The EPA’s proposed rule raised several compliance options that would prohibit effluent discharges of certain, but not all, waste streams and impose more stringent limitations on certain components in wastewater discharges from power plants. If enacted as proposed, we would be subject to the revised limitations beginning July 1, 2017, but no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impact on our operations if enacted as proposed. The EPA expects to finalize the rule in 2014.

Environmental Claims

As part of the transfer of generation assets that were transferred by CIPS to us in May 2000, CIPS, now Ameren Illinois, contractually agreed to indemnify us for claims relating to pre-existing environmental conditions at the transferred sites. The plant transfer agreement between us and CIPS, now Ameren Illinois, will be amended as part of the transaction agreement for Ameren to divest New AER to IPH. The agreement will specify that Medina Valley will assume all environmental liabilities associated with the Meredosia and Hutsonville energy centers. The agreement will also provide that all environmental liabilities associated with our Newton and Coffeen energy centers will no longer be indemnified by Ameren Illinois. See Note 2 - Assets Held for Sale for additional information.

Ash Management

There has been activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would

be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric generating units would apply to ash ponds and CCR management and intended to align this proposal with the CCR rules proposed in May 2010. Additionally, in January 2010, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. We are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. We are also evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.

The Illinois EPA has issued violation notices with respect to groundwater conditions existing at our ash pond systems.  In April 2013, AER filed a proposed rulemaking with the Illinois Pollution Control Board which, if approved, would provide for the systematic and eventual closure of ash ponds. The rulemaking process could take up to two years to complete. We changed our ARO fair value estimates for ash ponds to revise their expected retirement dates.

Asbestos-related Litigation

Currently, we own the former CIPS energy centers. As a condition to the transfer of ownership of the CIPS energy centers, CIPS, now Ameren Illinois, contractually agreed to indemnify us for liabilities associated with asbestos-related claims arising or existing from activities prior to the transfer in May 2000. The plant transfer agreement between us and CIPS, now Ameren Illinois, will be amended as part of the transaction agreement for Ameren to divest New AER to IPH. The amended plant transfer agreement will specify that Ameren Illinois will continue to retain asbestos exposure-related liabilities for claims arising or existing from activities prior to the transfer of the ownership of the CIPS energy centers to us. IPH will be responsible for any asbestos-related claims arising from activities that occur after it takes ownership of New AER. Any asbestos-related claims arising solely from activities post transfer of the energy centers from CIPS to us but prior to IPH taking ownership of New AER, of which there are currently none, will be retained by Ameren. See Note 2 - Assets Held for Sale for additional information.

EEI was not included in the plant transfer agreement with Ameren Illinois discussed above. As of March 31, 2013, five asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

Illinois Sales and Use Tax Exemptions and Credits

In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme

22

Court refused to hear an appeal of the case, and the decision became final. During the second quarter of 2010, we began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to our generation operations. The primary basis for those claims is that the determination in the Exelon casethat electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. In November 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois' position that EEI did not qualify for the manufacturing exemption it used during 2010. EEI is challenging the state of Illinois' position. In December 2011, EEI filed a request for review by the Informal Conference Board of the Illinois Department of Revenue. We do not believe that it is probable that the state of Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. From the second quarter of 2010 through December 31, 2011, we

claimed manufacturing exemptions and credits of $19 million, which represents the maximum potential tax liability, excluding any penalties assessed or interest accrued.

We did not claim any additional manufacturing exemptions or credits in 2012 and do not anticipate claiming any additional manufacturing exemptions or credits in 2013, pending discussions with the Illinois Department of Revenue. We are reserving the right to apply for applicable refunds at a later date.

Ameren will retain responsibility for this contingent liability after the divestiture of New AER is completed.

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

General

The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q as well as Management's Discussion and Analysis of Financial Condition and Results of Operations and Risk Factors contained in the Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changesin certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements.

We are headquartered in Collinsville, Illinois and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois. Much of our business was formerly owned and operated by CIPS. In 2000, we acquired from CIPS, at net book value, its coal-fired energy centers. Since then, we have constructed or purchased from other affiliates natural gas-fired energy centers. We have an 80% ownership interest in EEI that AER transferred to us in 2010 at net book value. We consolidate EEI for financial reporting purposes. EEI operates merchant electric generation facilities and FERC regulated transmission facilities in Illinois. We also consolidate our wholly owned subsidiary, Coffeen and Western Railroad Company, for financial reporting purposes.

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER, a subsidiary of AER to be formed prior to the closing, to IPH. Prior to the sale of New AER to IPH, AER will transfer to New AER substantially all of the assets and liabilities of AER, other than (i) any outstanding debt obligations of AER to Ameren or its other subsidiaries, except certain intercompany balances, (ii) all of the issued and outstanding equity interests in Medina Valley, which were distributed to Ameren in March 2013, (iii) the assets and liabilities associated with our Meredosia, Hutsonville, Elgin, Gibson City, and Grand Tower energy centers, (iv) obligations relating to Ameren's single-employer pension and postretirement benefit plans, and (v) the deferred tax positions associated with Ameren's ownership of

these retained assets and liabilities, to New AER. IPH will acquire all of the equity interests in New AER. Immediately prior to Ameren’s entry into the transaction agreement with IPH on March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. See Note 2 - Assets Held for Sale under Part 1, Item 1 of this report, for additional information.

Genco (parent) has a PSA with Marketing Company, whereby it agreed to sell and Marketing Company agreed to purchase all of the capacity and energy available from its generation fleet. Marketing Company entered into a similar PSA with AERG. Under these PSAs, revenues allocated between us and AERG are based on reimbursable expenses and generation of each entity. Each PSA will continue through December 31, 2022, and from year to year thereafter unless either party to the respective PSA elects to terminate the PSA by providing the other party with no less than six months advance written notice.

EEI has a PSA with Marketing Company, whereby EEI agreed to sell and Marketing Company agreed to purchase all of the capacity and energy available from EEI’s generation fleet. The price that Marketing Company pays for capacity is set annually based upon prevailing market prices. Marketing Company pays spot market prices for the associated energy. In addition, EEI may at times purchase energy from Marketing Company to fulfill obligations to a nonaffiliated party. This PSA will continue through May 31, 2016, unless either party elects to terminate the PSA in the event of a default.

See Note 3 - Related Party Transactions under Part I, Item 1, of this report for additional information on the power supply agreements.

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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. Ultimately, our sales are subject to market conditions for power. We principally use coal and natural gas for fuel in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We 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, 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 Genco was $129 million and $1 million in the first quarter of 2013 and 2012, respectively.

Earnings in the first three months of 2013, compared with the same period in 2012, were adversely affected by a charge to earnings to reflect the reduction in the carrying values of the Elgin, Gibson City and Grand Tower gas-fired energy centers to their estimated fair value less cost to sell. Additionally, reduced electric margins, which declined as a result of lower realized prices, negatively impacted earnings. The 2013 period benefited from a reduction in other operations and maintenance expenses, primarily as a result of lower maintenance costs and reduced charges for canceled projects.

For additional details regarding results of operations for the first quarter of 2013, including explanations of Margins, Other Operations and Maintenance Expenses, Asset Impairment, Depreciation and Amortization, Taxes Other Than Income Taxes, Interest Charges, and Income Taxes (Benefit), see the major headings below.

Margins

The following table presents the favorable (unfavorable) variations for electric margins in the three months ended March 31, 2013, compared with the same period in 2012. Electric margins are defined as electric revenues less fuel and purchased power costs. We consider electric margins useful measures to analyze the change in profitability of our operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

	2013 versus 2012
Electric revenue change:
Sales volume	$	42
Sales price changes, including hedge effect	(50		)
Other	(1		)
Total electric revenue change	$	(9	)
Fuel and purchased power change:
Fuel:
Production volume and other	$	(23	)
Net unrealized MTM gains	5
Total fuel and purchased power change	$	(18	)
Net change in electric margins	$	(27	)

Electric margins decreased by $27 million, or 30%, for the three months ended March 31, 2013, compared with the same period in 2012. Electric margins were unfavorably affected by lower revenues allocated under the Genco (parent) PSA with Marketing Company. There was a smaller pool of money to allocate because of lower sales prices, primarily due to the expiration of higher-priced hedges. We did experience marginally higher market prices associated with the EEI PSA. The combined impact under both PSAs resulted in an unfavorable price variance, which decreased revenues by $50 million.

The following items had a favorable impact on the electric margins:

• Higher retail sales attributed to Marketing Company’s efforts to sell power to residential and small commercial customers in Illinois and overall higher average spot market prices in 2013 compared with 2012. Consequently, sales volume grew, which increased revenues by $42 million. This increase was mitigated by a $23 millionincrease in production volume and other costs. Our energy centers’ average capacity factor increased to 74% in 2013, compared with 62% in 2012. The equivalent availability factor decreased to 82% in 2013, compared with 89% in 2012.

• Net unrealized MTM gains on fuel-related contracts increased margins by $5 million.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses were $16 million lower in the first quarter of 2013, as compared with the first quarter of 2012, primarily due to lower maintenance costs of $12 million, as a result of fewer outages at our energy centers and disciplined cost management, and reduced charges for canceled projects of $4 million.

Asset Impairment

On March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval.

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As the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers met the held for sale criteria at March 31, 2013, we evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value less cost to sell. The estimated fair value was determined by reference to the amended put option agreement, the asset purchase agreement with Medina Valley, and the transaction agreement with IPH. As a result, we recorded a pretax charge to earnings of $207 million for the three months ended March 31, 2013, to reflect the impairment of the Elgin, Gibson City and Grand Tower gas-fired energy centers. The impairment recorded during the first quarter of 2013 primarily related to the Gibson City and Grand Tower energy centers as the Elgin energy center was previously impaired under held and used accounting guidance during the fourth quarter of 2012.

After impairments recognized in the fourth quarter of 2012 and the first quarter of 2013, we believed the carrying value of our energy centers exceeded their estimated realizable fair value under current market conditions by an amount in excess of $1 billion. We will continue to monitor the market price for power and the related impact on electric margin, our liquidity needs, and other events or changes in circumstances that indicate that the carrying value of our energy centers may not be recoverable as compared to their undiscounted cash flows. We could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted cash flows no longer exceed carrying values for long-lived assets. This may occur either as a result of factors outside our control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of our energy centers, and also as a result of factors that may be within our control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball, or sell energy centers. As of March 31, 2013, the carrying value of long-lived assets not classified as held for sale was $1.9 billion.

See Note 2 - Assets Held for Sale under Part I, Item 1 of this report for additional information.

Depreciation and Amortization

Depreciation and amortization expenses were comparable between the first quarter of 2013 and 2012.

Taxes Other Than Income Taxes

Taxes other than income taxes were comparable between the first quarter of 2013 and 2012.

Interest Charges

Interest charges decreased by $3 million in the first quarter of 2013, as compared with the first quarter of 2012, primarily because of increased capitalized interest for the Newton energy center scrubber project.

Income Taxes (Benefit)

The effective income tax rate was 40% and (200)% for the three months ended March 31, 2013, and 2012, respectively. The rate is higher primarily due to the impact of tax credits and changes in reserves for uncertain tax positions on low pretax loss in 2012. The first quarter of 2012 effective tax rate was impacted by the low pretax book income used in the estimated annual effective tax rate calculation.

LIQUIDITY AND CAPITAL RESOURCES

Through Marketing Company, we sell power primarily through market-based contracts with wholesale and retail customers to generate operating cash flows. In December 2012, Ameren announced its intentions to exit the merchant generation business, of which we are a part, and on March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 2 - Assets Held for Sale under Part I, Item 1, of this report for additional information. While we remain a business of Ameren, we will seek to fund our operations internally and therefore will seek not to rely on financing from Ameren. We will seek to defer or reduce capital and operating expenses and to take other actions as necessary to fund our operations internally while maintaining safe and reliable operations. Additionally, we have the potential to receive proceeds from our tax allocation agreement with Ameren through its ownership period. See Note 1 - Summary of Significant Accounting Policies in the Form 10-K for additional information related to the tax allocation agreement. The 2010 Genco Credit Agreement was terminated in November 2012 and not replaced.

Under the provisions of our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is less than a specified minimum or if our debt-to-capital ratio is greater than a specified maximum. See Note 5 - Long-term Debt under Part I, Item 1, of this report for additional information on our indenture provisions. During the first quarter of 2013, our interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and we expect the ratio to remain less than this minimum level through at least 2015. As a result, our ability to borrow additional funds from external, third-party sources is restricted. Our 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. Ameren’s transaction agreement with IPH requires Ameren to operate New AER in the ordinary course prior to closing. Should a financing need arise, our 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, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. We advanced the initial payment amount we received to the non-state-regulated subsidiary money pool. Based on current projections, assuming we remain a subsidiary

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of Ameren for the entire year, excluding the amount received related to the put option, we expect operating cash flows to approximate nonoperating cash flow requirements in 2013. Should FERC approval not be obtained or the transfer of the Elgin, Gibson City, and Grand Tower energy centers cannot be completed, we will be required to return to Medina Valley the initial payment received in March 2013.

The following table presents net cash provided by (used in) operating, investing and financing activities for the three months ended March 31, 2013, and 2012:

	2013			2012			Variance
Net cash provided by operating activities	$	39		$	46		$	(7	)
Net cash used in investing activities	(39		)	(54		)	15
Net cash provided by financing activities	—			—			—

Cash Flows from Operating Activities

Cash from operating activities decreased in the first three months of 2013 compared with the first three months of 2012, primarily due to a $32 million decrease in electric margins, excluding impacts of noncash MTM transactions, as discussed in Results of Operations.

Cash flows from operating activities during the first three months of 2013, compared with the same period in 2012, were favorably affected by the following items:

• Income tax refunds of $6 million in 2013, compared with income tax payments of $11 million in 2012, primarily due to lower pretax book income partially offset by a reduction in accelerated depreciation deductions.

• A $6 million decrease in coal inventory, primarily due to continued focus on inventory reductions.

Cash Flows from Investing Activities

Cash flows used in investing activities decreased during the three months endedMarch 31, 2013, compared with the same period in 2012, principally attributable to proceeds received from Medina Valley for the pending asset sale and a decrease in capital expenditures partially offset by an increase in net money pool advances. During the first three months of 2013, capital expenditures decreased by $21 million primarily because of decreased expenditures for the Newton energy center scrubber project. Additionally, during the first quarter of 2013, cash provided by operating activities exceeded capital expenditures by $27 million creating a surplus. We also received an initial payment of $100 million from Medina Valley in connection with the pending asset sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers. We contributed the surplus and the proceeds from the pending asset sale to Ameren’s non-state-regulated subsidiary money pool. During the three months ended March 31, 2012, our cash provided by operating activities exceeded capital expenditures by $13 million. We contributed

this surplus and cash on hand to Ameren’s non-state regulated subsidiary money pool.

We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other things. Any changes that we may plan to make for future generation needs could result in significant capital expenditures or losses being incurred, which could be material.

We 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 coal-fired energy centers. See Note 8 – Commitments and Contingencies under Part I, Item 1, of this report 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 cooling water intake structures, the MATS, and the stayed CSAPR, as of March 31, 2013.

Cash Flows from Financing Activities

In the first quarter of 2013 and 2012, we met our working capital and investing requirements without utilizing financing.

Short-term Borrowings and Liquidity

Our liquidity needs are typically supported through the use of available cash on hand, a return of money pool advances, or money pool borrowings at the discretion of Ameren. Ameren's credit agreements were available for use, subject to applicable regulatory short-term borrowing authorizations, through direct short-term borrowings from Ameren and through a 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. Ameren Services is responsible for operation and administration of the money pool agreements. See Note 4 - Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information on short-term borrowing activity, and relevant interest rates, and borrowings under Ameren's money pool arrangement.

Genco has unlimited long and short-term debt issuance authorization from FERC. EEI has unlimited short-term debt authorization from FERC.

Long-term Debt and Equity

There were no issuances of common stock, and no issuances, redemptions, repurchases, or maturities of long-term debt, during the three months ended March 31, 2013 or 2012.

Indebtedness Provisions and Other Covenants

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See Note 5 - Long-term Debt under Part I, Item 1, of this report for a discussion of covenants and provisions contained in our indenture.

At March 31, 2013, we were in compliance with the provisions and covenants contained within our indenture.

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 our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is less than a specified minimum or if our debt-to-capital ratio is greater than a specified maximum. During the first quarter of 2013, our interest coverage ratio fell to a level less than the specified minimum level required for external borrowings, and we expect the ratio to remain less than this minimum level through at least 2015. As a result, our ability to borrow additional funds from external, third-party sources is restricted. Our indenture does not restrict intercompany borrowings from Ameren's non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren's control. If an intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool would be dependent on consideration by Ameren of the facts and circumstances existing at that time. We will seek to fund operations internally and therefore seek not to rely on financing from Ameren. Ameren’s transaction agreement with IPH requires Ameren to operate AER in the ordinary course prior to the closing.

On March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. In 2013, we expect to receive at least an additional $33 million depending on the appraised value of these energy centers or the value realized from Medina Valley’s sale of these energy centers to a third party. These put option proceeds, along with cash on hand and the return of money pool advances are our primary sources of liquidity. Based on current projections, assuming we remain a subsidiary of Ameren for the entire year, excluding the amount received related to the put option, we expect operating cash flows to approximate nonoperating cash flow requirements in 2013. See Note 2 - Assets Held for Sale under Part I, Item 1, of this report for additional information regarding the amended put option agreement.

Dividends

Our indenture includes restrictions that can prohibit us from making dividend payments on our common stock. Specifically, dividends cannot be paid unless the 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 March 31, 2013, of operating results and cash flows in 2013 and 2014, we do not expect that we will achieve the minimum interest coverage ratio

necessary to pay dividends on our common stock for each of the subsequent four six-month periods ending September 30, 2013, March 31, 2014, September 30, 2014, or March 31, 2015. As a result, we were restricted from paying dividends as of March 31, 2013, and we expect to be unable to pay dividends on our common stock through at least March 31, 2016. See Note 5 - Long-term Debt under Part I, Item 1, of this report and Note 5 - Long-term Debt under Part II, Item 8, of the Form 10-K, for additional information on indenture provisions. No dividends were paid to our parent, AER, for the three months ended March 31, 2013 and 2012.

Contractual Obligations

For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7, and Note 10 - Commitments and Contingencies under Part II, Item 8, of the Form 10-K, and Other Obligations in Note 8 - Commitments and Contingencies under Part I, Item 1, of this report.

At March 31, 2013, total other obligations related to the procurement of coal and natural gas, among other agreements, were $473 million. Total unrecognized tax benefits at March 31, 2013, were $7 million.

Off-Balance-Sheet Arrangements

At March 31, 2013, we did not have any off-balance-sheet financing arrangements other than operating leases entered into in the ordinary course of business. We do not expect to engage in any significant off-balance-sheet financing arrangements in the near future.

Credit Ratings

Credit ratings affect our liquidity, our access to the capital markets and credit markets, and collateral posting requirements under commodity contracts.

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

	Moody’s	S&P	Fitch
Issuer/corporate credit rating	—	CCC+	CC
Senior unsecured debt	B3	CCC+	CCC-

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

Collateral Postings

Any adverse change in our credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of

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borrowing and fuel, power, and natural gas supply, among other things, resulting in a negative impact on earnings. As of March 31, 2013, we had no cash collateral postings and $2 million in prepayments with external parties, including postings related to exchange-traded contracts. We did not hold any cash collateral from external counterparties. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at March 31, 2013, could have resulted in us being required to post additional collateral or other assurances for certain trade obligations amounting to $40 million.

Changes in commodity prices could trigger additional collateral postings and prepayments at current credit ratings. If market prices were 15% higher than March 31, 2013, levels in the next 12 months and 20% higher thereafter through the end of the term of the commodity contracts, then we could be required to post additional collateral or other assurances for certain trade obligations up to $35 million. If market prices were 15% lower than March 31, 2013, levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity contracts, then we could be required to post additional collateral or other assurances for certain trade obligations up to $42 million.

OUTLOOK

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

• In 2012, under the terms of the Genco PSA with Marketing Company, we were allocated revenues attributable to the Elgin, Gibson City, and Grand Tower gas-fired energy centers that approximated their operating expenses, excluding the December 2012 long-lived asset impairment charge relating to the Elgin energy center. However, the sale of these energy centers to Medina Valley will impact the allocation of revenues between us and AERG going forward and could result in a material change to our results of operations depending on our reimbursable costs compared to AERG's reimbursable costs, our generation level compared to AERG's generation level, and Marketing Company's realized revenues.

• Effective with our conclusion in March 2013 that the Elgin, Gibson City and Grand Tower gas-fired energy centers met the criteria for held for sale presentation, we suspended recording depreciation on these energy centers.

• After impairments recognized in the fourth quarter of 2012 and the first quarter of 2013, we believed the carrying value of our energy centers exceeded their estimated realizable fair value under current market conditions by an amount in excess of $1 billion. We could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted cash flows no longer exceed carrying values for long-lived assets. This may occur as a result of factors outside our control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws

and regulations that could reduce the expected useful lives of our energy centers, and also as a result of factors that may be within our control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell energy centers. As of March 31, 2013, the carrying value of long-lived assets not classified as held for sale was $1.9 billion. Impairments could result in lower revenues under certain cost-based contracts, which are included in the forward sales information below.

• Previously, Ameren announced its intention to exit the merchant generation business, of which we are a part, and on March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 2 - Assets Held for Sale under Part I, Item 1, of this report for additional information.

• As of March 31, 2013, we expected to have available generation from our coal-fired energy centers of 24 million megawatthours in any given year. However, based on currently expected power prices, we expect to generate approximately 20 million megawatthours in 2013, with approximately 94% of this generation expected to be from coal-fired energy centers.

• Power prices in the Midwest affect the amount of revenues and cash flows we can realize, through Marketing Company, by marketing power into the wholesale and retail markets. We are adversely affected by the declining market price of power for any unhedged generation. Market prices for power have decreased over the past several years.

• As of March 31, 2013, Marketing Company had sold forward approximately 21 million megawatthours of our expected generation for 2013, at an average price of $36 per megawatthour. Megawatt hours sold forward in excess of our actual generation will be purchased from the market as needed. For 2014, Marketing Company had hedged approximately 10 million megawatthours of our forecasted generation sales at an average price of $38 per megawatthour. For 2015, Marketing Company had hedged approximately 5 million megawatthours of our 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. We expect 2013 margins to be lower than 2012 due to the expiration of higher priced contracts.

• To further reduce cash flow volatility, we seek to hedge fuel costs consistent with power sales. As of March 31, 2013, for 2013 we had hedged fuel costs for approximately 18 million megawatthours of coal and up to 19 million megawatthours of base transportation at about $23 per megawatthour. For 2014, we had hedged fuel costs for approximately 9 million megawatthours of coal and up to 14 million megawatthours of base transportation at about $24 per megawatthour. For 2015, we had hedged fuel costs for approximately 4 million megawatthours of coal and up to 14 million megawatthours of base transportation at about $26 per megawatthour. See

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Item 3 - Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about the percentage of fuel and transportation requirements that are price-hedged for 2013 through 2017.

• Along with Marketing Company, we continue 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. Excluding the capacity related to the Elgin energy center, which is located within PJM, Marketing Company has sold 150 megawatts of capacity associated with our energy centers from June 2015 to May 2016, and expects to sell 431 megawatts of capacity associated with our energy centers after June 2016. 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. These additional revenues will be allocated to us under the PSA.

• 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 the 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. 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 AER’s variance related to the Illinois MPS. AER and Dynegy filed a transfer request with the Illinois Pollution Control Board on May 2, 2013.

• EEI reduced its workforce in 2012. Going forward, the workforce reduction is expected to reduce EEI’s annual pretax other operations and maintenance expenses by $2 million to $3.5 million. Additionally, EEI’s management and labor union postretirement medical benefit plans were amended in 2012 to adjust for moving to a Medicare Advantage plan, which resulted in a reduction of the benefit obligation. We estimate the pretax impact of the lower benefit obligation will result in a $5 million to $10 million reduction in postretirement benefits expense during 2013.

Liquidity and Capital Resources

• We seek to fund our operations internally and not to rely on financing from Ameren or external, third-party sources. We will continue to seek to defer or reduce capital and operating expenses and to take other actions as necessary to fund our operations internally while maintaining safe and reliable operations. On March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. In 2013, we expect to receive at least an additional $33 million depending on the appraised value of these energy centers or the value realized from Medina Valley’s sale to a third-party buyer. These put option proceeds, along with available cash on hand, the return of money pool advances, and money pool borrowings at the direction of Ameren are our primary sources of liquidity. Based on projections as of March 31, 2013, we estimate that these financing sources are adequate to support our operations in 2013. If we do not receive FERC approval for the transfer of the Elgin, Gibson City, and Grand Tower energy centers, we will be required to return to Medina Valley the initial payment received in March 2013.

• Under the provisions of our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is less than a specified minimum or if our debt-to-capital ratio is greater than a specified maximum. During the first quarter of 2013, our interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and we expect the ratio to remain less than this minimum level through at least 2015. As a result, our ability to borrow additional funds from external, third-party sources is restricted. Our 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. Ameren’s transaction agreement with IPH requires Ameren to operate AER in the ordinary course prior to the closing.

• Based on current projections for 2013, assuming we remain a subsidiary of Ameren for the entire year, excluding the put option receipts, we expect operating cash flows to approximate nonoperating cash flow requirements in 2013. Included in this 2013 projection, we expect to receive income tax benefits through the tax allocation agreement with Ameren of approximately $60 million. These estimates may change significantly depending on the taxable income or loss of Ameren and each of its subsidiaries and also assume we remain a subsidiary of Ameren for all of 2013.

• As of March 31, 2013, we had approximately $100 million in federal income tax net operating loss carryforwards and $1 million in federal income tax credit carryforwards. These carryforwards are expected to offset income tax liabilities into 2015, consistent with the tax allocation agreement. If we are no longer a subsidiary of Ameren, the tax allocation agreement will terminate and it is probable that some or all of our tax carryforwards will not be utilized.

• If the transaction with IPH is completed, we expect the tax basis of our property, plant and equipment to decrease and

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our deferred tax assets related to federal and state income tax net operating loss carryforwards and income tax credits to decrease with corresponding offsets to equity. The amount of any such decrease is dependent on the value and timing of the New AER divestiture transaction.

• After Ameren’s divestiture of New AER is complete, we will not have access to Ameren’s liquidity support.

• In December 2011, the IRS issued new guidance on the treatment of amounts paid to acquire, produce or improve tangible property and dispositions of such property with respect to electric transmission, distribution, and generation assets as well as natural gas transmission and distribution assets. These new rules are required to be implemented no later than January 1, 2014. In addition, in April 2013, the IRS issued new guidance defining when expenditures to maintain, replace or improve steam or electric power generation property must be capitalized. This April 2013 guidance may change how Ameren determines whether expenditures related to plant and equipment are deducted as repairs or capitalized for income tax purposes. Until we complete our evaluation of the new guidance, we cannot estimate its impact on our results of operation, financial position, and liquidity.

• Investments required to achieve compliance with known environmental laws and regulations from 2013 to 2022 are expected to be more than $350 million. We continue 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. The recoverability of our capital investments will depend on whether market prices for power change to reflect increased environmental costs for coal-fired energy centers.

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. 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 8 – Commitments and Contingencies under Part I, Item 1, of this report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity

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

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

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

Credit Risk

Credit risk represents the loss that would be recognized if counterparties should fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction. See Note 6 – Derivative Financial Instruments under Part I, Item 1, of this report for information on the potential loss on counterparty exposure as of March 31, 2013.

Our physical and financial instruments are subject to credit risk consisting of accounts receivable and executory contracts with market risk exposures. Our revenues are primarily derived from sales of electricity to Marketing Company as described in Note 3 - Related Party Transactions, under Part I, Item 1 of this report and in Note 2 - Related Party Transactions in the Form 10-K. At March 31, 2013, approximately $67 million of our accounts receivable was a related party receivable from Marketing Company. No other customer represents greater than 10% of our accounts receivable.

At March 31, 2013, the combined credit exposures to coal suppliers deemed below investment grade either through external or internal credit evaluations, net of collateral, was less than $1 million (2012 - $0).

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

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counterparty’s financial condition before we enter into sales, forwards, swaps, futures, or option contracts.

Equity Price Risk

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

Commodity Price Risk

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

Risk of changes in prices for power sales are partially hedged through sales agreements. Through Marketing Company, we seek to sell power forward to wholesale, municipal, and industrial customers to limit exposure to changing prices. We also attempt to mitigate financial risks through risk management programs and policies, which include forward-hedging programs, and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). However, a portion of our generation capacity is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.

If power prices were to decrease by 1% on unhedged economic generation for 2013 through 2017, earnings would decrease $13 million, based on a 42% estimated tax rate.

Through Marketing Company, we use derivative financial swap contracts as part of our forward-hedging power programs. These swap contracts financially settle a fixed price against a floating price. The floating price is typically the realized, or settled, price at a liquid regional hub at some forward period of time. We control the use of derivative financial swap contracts with volumetric and correlation limits that are intended to mitigate any material adverse financial impact.

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

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

Transportation costs for coal and natural gas can be a significant portion of fuel costs. We typically hedge coal transportation forward to provide supply certainty and to mitigate transportation price volatility. Natural gas transportation expenses

for our gas-fired generation units are regulated by FERC through approved tariffs governing the rates, terms, and conditions of transportation and storage services. Certain firm transportation and storage capacity agreements include rights to extend the term of contracts. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariff rates for our requirements.

In addition, coal transportation costs are sensitive to the price of diesel fuel as a result of rail freight fuel surcharges. We use forward fuel oil contracts (both for heating oil, ultra-low sulfur diesel and crude oil) to mitigate this market price risk as changes in these products are highly correlated to changes in diesel markets. If diesel fuel costs were to increase or decrease by $0.25 a gallon, our fuel expense could increase or decrease by $4 million annually. As of March 31, 2013, we had a price cap for 92% of expected fuel surcharges in 2013.

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

The following table presents, as of March 31, 2013, the percentages of the projected required supply of coal and coal transportation for our coal-fired energy centers and natural gas for our CTs that are price-hedged over the five-year period 2013 through 2017. The projected required supply of these commodities could be significantly affected by changes in our assumptions for matters such as customer demand for our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.

	2013		2014		2015 – 2017
Coal	95	%	47	%	14	%
Coal transportation	100		73		73
Natural gas for generation	96		100		—

The following table shows how our total fuel expense might increase and how our net income might decrease if coal and coal transportation costs were to increase by 1% on any requirements not currently covered by fixed-price contracts for the five-year period 2013 through 2017.

	Fuel Expense		Net Income(a)
Coal	$	6	$	(3	)
Coal transportation	3		(2		)

(a) Calculations are based on an estimated tax rate of 42%.

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

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See Note 8 – Commitments and Contingencies under Part I, Item 1, of this report for additional information.

Fair Value of Contracts

We use derivatives principally to manage the risk of changes in market prices for coal, natural gas, diesel, and power. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three months ended March 31, 2013. We use various methods to determine the fair value of our contracts. In accordance with authoritative accounting guidance for fair value hierarchy levels, the sources we used to determine the fair value of these contracts were active quotes (Level 1), inputs

corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). See Note 7 - Fair Value Measurements under Part I, Item 1, of this report for further information regarding the methods used to determine the fair value of these contracts.

Fair value of contracts at beginning of period, net	$	(7	)
Contracts realized or otherwise settled during the period	1
Changes in fair values attributable to changes in valuation technique and assumptions	—
Fair value of new contracts entered into during the period	1
Other changes in fair value	4
Fair value of contracts outstanding at end of period, net	$	(1	)

The following table presents maturities of derivative contracts as of March 31, 2013, based on the hierarchy levels used to determine the fair value of the contracts:

Sources of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years		Maturity in Excess of 5 Years		Total Fair Value
Level 1	$	(1	)	$	(1	)	$	—	$	—	$	(2	)
Level 2	—			—			—		—		—
Level 3(a)	1			—			—		—		1
Total	$	—		$	(1	)	$	—	$	—	$	(1	)

(a) Principally option contract values based on our estimates.

ITEM 4. CONTROLS AND PROCEDURES.

(a) Evaluation of Disclosure Controls and Procedures

As of March 31, 2013, an evaluation was performed under the supervision and with the participation of management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of Genco’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon that evaluation, the principal executive officer and principal financial officer concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in Genco’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control over Financial Reporting

There has been no change in internal control over financial reporting during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS.

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. Material legal and administrative proceedings, which are discussed in Note 8 - Commitments and Contingencies and Note 2 - Assets Held for Sale under Part I, Item 1, of this report or Note 10 - Commitments and Contingencies and Note 12 - Subsequent Events under Part II, Item 8, of the Form 10-K and incorporated herein by reference, include the following:

• the EPA’s Clean Air Act-related NSR investigations and the Notice of Violation for alleged permitting violations;

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• litigation alleging that the CO₂ emissions from several industrial companies, including CO₂ emissions from our energy centers, created the atmospheric conditions that intensified Hurricane Katrina;

• our challenge before the Informal Conference Board of the Illinois Department of Revenue regarding the State’s position that EEI did not qualify for manufacturing tax exemptions for 2010 transactions;

• the request for FERC and FCC approvals, as well as the Illinois Pollution Control Board’s transfer of AER’s variance relating to the Illinois MPS, in connection with Ameren’s divestiture of New AER to IPH; and

• our request for FERC approval of our transfer of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley.

ITEM 1A. RISK FACTORS.

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

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

There is no established trading market for our common stock. We did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from January 1, 2013, to March 31, 2013. As of March 31, 2013, our parent, Ameren Energy Resources Company, LLC, owned all of our outstanding common stock.

ITEM 6. EXHIBITS.

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

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herewith: 

Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit  to:
Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1	Transaction Agreement, dated March 14, 2013, between Ameren and IPH	March 19, 2013 Form 8-K, Exhibit 2.1, File No. 1-14756
2.2	Asset Purchase Agreement, dated March 14, 2013, by and between Medina Valley and Genco	March 19, 2013 Form 8-K, Exhibit 2.2, File No. 1-14756
Material Contracts
10.1	Novation and Amendment of Put Option Agreement, dated March 14, 2013, by and among Medina Valley, AERG, Genco and Ameren	March 19, 2013 Form 8-K, Exhibit 10.3, File No. 1-14756
10.2	*Employment and Change of Control Agreement, dated March 13, 2013, between Steven R. Sullivan, AER and Ameren	March 19, 2013 Form 8-K, Exhibit 10.4, File No. 1-14756
Statement re: Computation of Ratios
12.1	Statement of Computation of Ratio of Earnings to Fixed Charges
Rule 13a-14(a)/15d-14(a) Certifications
31.1	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer
31.2	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer
Section 1350 Certifications
32.1	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer
Interactive Data File
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Document

The file number reference for Genco's filings with the SEC is 333-56594.

*Compensatory plan or arrangement.

** Attached as Exhibit 101 to this report is the following financial information from Genco’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statement of Income (Loss) and Comprehensive Income (Loss) for the three months ended March 31, 2013, and 2012, (ii) the Consolidated Balance Sheet at March 31, 2013, and December 31, 2012, (iii) the Consolidated Statement of Cash Flows for the three months ended March 31, 2013, and 2012, and (iv) the Notes to the Financial Statements for the three months ended March 31, 2013. These exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.

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

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SIGNATURES

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

AMEREN ENERGY GENERATING COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

Date: May 15, 2013

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