Illinois Power Generating 10-Q 12 Nov 13 2013 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 31, 2013
Entity Information [Line Items]	'	'
Entity Registrant Name	'AMEREN ENERGY GENERATING CO	'
Entity Central Index Key	'0001135361	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Non-accelerated Filer	'
Document Type	'10-Q	'
Document Period End Date	30-Sep-13	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Amendment Flag	'false	'
Entity Common Stock, Shares Outstanding	'	2,000

Consolidated_Statement_of_Inco

Consolidated Statement of Income (Loss) and Comprehensive Income (Loss) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating Revenues (Note 3) :	'	'	'	'
Electric	$274	$218	$644	$606
Other	1	'	5	'
Total operating revenues	275	218	649	606
Operating Expenses:	'	'	'	'
Fuel	124	122	353	352
Purchased power	102	1	142	1
Other operations and maintenance	32	41	112	133
Assets held for sale and impairment adjustments (Note 2)	-5	'	197	'
Depreciation and amortization	18	15	60	61
Taxes other than income taxes	4	5	14	16
Total operating expenses	275	184	878	563
Operating Income (Loss)	'	34	-229	43
Miscellaneous income	1	1	1	1
Miscellaneous expense	'	1	'	1
Total other income	1	'	1	'
Interest Charges	10	14	31	40
Income (Loss) Before Income Taxes (Benefit)	-9	20	-259	3
Income Taxes (Benefit)	-4	9	-103	1
Net Income (Loss)	-5	11	-156	2
Less: Net Loss Attributable to Noncontrolling Interest	'	-2	'	-6
Net Income (Loss) Attributable to Ameren Energy Generating Company	-5	13	-156	8
Other Comprehensive Income (Loss), Net of Tax [Abstract]	'	'	'	'
Reclassification adjustments for derivative losses included in net income, net of income taxes of $-, $-, $- and $-, respectively	1	'	1	'
Pension and other postretirement benefit plan activity, net of income taxes of $-, $30, $1 and $33, respectively	'	43	2	48
Total other comprehensive income, net of taxes	1	43	3	48
Comprehensive Income (Loss)	-4	54	-153	50
Less: Comprehensive Income Attributable to Noncontrolling Interest	'	7	'	3
Comprehensive Income (Loss) Attributable to Ameren Energy Generating Company	($4)	$47	($153)	$47

Consolidated_Statement_of_Inco1

Consolidated Statement of Income (Loss) and Comprehensive Income (Loss) (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Statement [Abstract]	'	'	'	'
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	'	'	'	'
Reclassification adjustments for derivative income taxes (benefit)	'	$30	$1	$33

Consolidated_Balance_Sheet

Consolidated Balance Sheet (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Current Assets:	'	'
Cash and cash equivalents	$25	$25
Advances to money pool	166	27
Accounts receivable – affiliates	57	70
Miscellaneous accounts receivable	24	20
Materials and supplies	70	85
Other current assets	17	28
Assets held-for-sale	152	364
Total current assets	511	619
Property and Plant, Net	1,881	1,887
Other Assets	24	26
TOTAL ASSETS	2,416	2,532
Current Liabilities:	'	'
Accounts and wages payable	51	54
Accounts payable – affiliates	12	12
Deposit received from affiliate for pending asset sale	100	'
Current portion of tax payable – Ameren Illinois	6	6
Taxes accrued	10	14
Interest accrued	27	12
Mark-to-market derivative liabilities	5	8
Current accumulated deferred income taxes, net	37	'
Other current liabilities	7	9
Liabilities held-for-sale	15	25
Total current liabilities	270	140
Long-term Debt, Net	824	824
Deferred Credits and Other Liabilities:	'	'
Accumulated deferred income taxes, net	254	334
Accumulated deferred investment tax credits	1	2
Tax payable – Ameren Illinois	37	39
Asset retirement obligations	68	59
Pension and other postretirement benefits	79	92
Other deferred credits and liabilities	8	14
Total deferred credits and other liabilities	447	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	0	0
Other paid-in capital	656	656
Retained earnings	248	404
Accumulated other comprehensive loss	-37	-40
Total Ameren Energy Generating Company stockholder’s equity	867	1,020
Noncontrolling Interest	8	8
Total equity	875	1,028
TOTAL LIABILITIES AND EQUITY	$2,416	$2,532

Consolidated_Balance_Sheet_Par

Consolidated Balance Sheet (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]	'	'
Common stock, no par value	'	'
Common stock, shares authorized	10,000	10,000
Common stock, shares outstanding	2,000	2,000

Consolidated_Statement_of_Cash

Consolidated Statement of Cash Flows (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Cash Flows From Operating Activities:	'	'
Net income (loss)	($156)	$2
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'
Loss on asset impairment	197	'
Net (gain) loss on sales of properties	-1	1
Net mark-to-market (gain) loss on derivatives	-3	10
Depreciation and amortization	60	61
Amortization of debt issuance costs and premium/discounts	1	2
Deferred income taxes and investment tax credits, net	-35	12
Other	1	8
Changes in assets and liabilities:	'	'
Receivables	9	22
Materials and supplies	23	7
Accounts and wages payable	-9	'
Taxes accrued	-5	-7
Assets, other	-2	-3
Liabilities, other	8	-7
Pension and other postretirement benefits	-10	3
Net cash provided by operating activities	78	111
Cash Flows From Investing Activities:	'	'
Capital expenditures	-40	-140
Deposit received from affiliate for pending asset sale	100	'
Proceeds from sales of properties	1	4
Money pool advances, net	-139	42
Net cash used in investing activities	-78	-94
Cash Flows From Financing Activities:	'	'
Net cash provided by financing activities	0	0
Net change in cash and cash equivalents	'	17
Cash and cash equivalents at beginning of year	25	8
Cash and cash equivalents at end of period	$25	$25

Summary_of_Significant_Account

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	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 the 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 Ameren 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 pre-tax noncash long-lived asset impairment charge of $70 million 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, we 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, which Ameren expects will close during the fourth quarter of 2013. Immediately prior to Ameren’s entry into the transaction agreement with IPH, on March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million with respect to the sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. On October 11, 2013, Ameren received FERC approval for the divestiture of New AER to IPH and our sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. Immediately after receipt of FERC approval, we completed the sale of these gas-fired energy centers to Medina Valley and received additional cash proceeds of $37.5 million. Medina Valley has entered into an agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. Ameren expects this third-party sale of these gas-fired energy centers to close by the end of 2013, subject to FERC and other regulatory approvals. See Note 2 - Assets Held for Sale for additional information.
	We determined that the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers first qualified for held for sale presentation beginning March 14, 2013. 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 September 30, 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.
	Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.
	Uncertain Tax Positions
	The amount of unrecognized tax benefits as of September 30, 2013, was $5 million. Unrecognized tax benefits are included in “Other deferred credits and liabilities” on our consolidated balance sheet. This amount of unrecognized tax benefits as of September 30, 2013, would have no impact on the effective tax rate, if recognized.
	During the three months ended September 30, 2013, unrecognized tax benefits related to the deductibility of expenditures to maintain, replace, or improve steam or electric power generation property were reduced by $4 million, with an offset to “Accumulated deferred income taxes, net”. This was the result of recent Internal Revenue Service guidance establishing new rules for the amount and timing of these deductions.
	We are included in Ameren’s federal income tax return. Ameren’s federal income tax returns for the years 2007 through 2011 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2012 is currently under examination.
	It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the next 12 months for the years 2007 through 2011. This settlement, which is primarily related to uncertain tax positions for research tax deductions, is expected to result in a decrease in uncertain tax benefits of $5 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 Internal Revenue Service 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 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
	Our 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 on the consolidated balance sheet. A reconciliation of the equity changes attributable to our noncontrolling interests for the three and nine months ended September 30, 2013, and 2012, is shown below:
		Three Months							Nine Months
		2013				2012			2013				2012
	Noncontrolling interest, beginning of period	$	8			$	3		$	8			$	7
	Net loss attributable to noncontrolling interest	—				(2		)	—				(6		)
	Other comprehensive income attributable to noncontrolling interest(a)	—				9			—				9
	Noncontrolling interest, end of period	$	8			$	10		$	8			$	10
	(a)	Represents the noncontrolling interest of EEI’s pension and other postretirement benefit plan activity, net of income taxes of $-, $6, $-, and $6, respectively.
	Asset Retirement Obligations
	The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the nine months ended September 30, 2013:
	Balance at December 31, 2012	$	59
	Liabilities settled	(a)
	Accretion	3
	Change in estimates(b)	6
	Balance at September 30, 2013	$	68
	(a)	Less than $1 million.
	(b)	We changed our estimate due to updated retirement dates for certain CCR storage facilities during the first quarter of 2013. See Note 8 - Commitments and Contingencies for additional information regarding this change in estimate.
	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 idle Meredosia and Hutsonville energy centers, which were estimated at $27 million as of September 30, 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 “Liabilities held for sale” as of September 30, 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 October 2013 sale of the Grand Tower energy center to Medina Valley and the transfer at the closing of Ameren’s New AER divestiture 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.
	Under the terms of the transaction agreement to divest New AER to IPH, 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 $32 million at September 30, 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 at September 30, 2013.
	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 the three and nine months ended September 30, 2013, and 2012:
		Pension Benefits(a)															Postretirement Benefits(a)
		Three Months							Nine Months								Three Months						Nine Months
		2013				2012			2013				2012				2013			2012			2013			2012
	Service cost	$	1			$	1		$	3			$	3			$	—		$	1		$	1		$	3
	Interest cost	2				3			7				8				1			1			3			4
	Expected return on plan assets	(3		)		(3		)	(10		)		(9		)		(1		)	(1		)	(4		)	(4		)
	Amortization of:
	Prior service cost (benefit)	—				—			—				—				(2		)	—			(6		)	—
	Actuarial loss	2				1			6				3				1			1			3			3
	Curtailment loss	—				2			—				2				—			—			—			—
	Net periodic benefit cost	$	2			$	4		$	6			$	7			$	(1	)	$	2		$	(3	)	$	6
	(a)	Includes amounts for our participation in Ameren’s single-employer plans and the cost of EEI’s plans.
	We are allocated a share of the net periodic benefit costs for pension and postretirement benefits for Ameren Services employees doing work on our behalf. The following table presents these costs for the three and nine months ended September 30, 2013, and 2012:
			Pension Benefits										Postretirement Benefits
			Three Months					Nine Months					Three Months				Nine Months
			2013			2012		2013		2012			2013		2012		2013		2012
	Allocated benefit costs	$	1		$	(a)	$	2	$	1		$	(a)	$	(a)	$	(a)	$	(a)
	(a)	Less than $1 million.
	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, as well as guidance issued but not yet adopted, 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 required 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 amended guidance 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 and derivatives. For the three and nine months ended September 30, 2013, the pension and other postretirement plan and derivative activity were immaterial.
	Disclosures about Offsetting Assets and Liabilities
	In December 2011, FASB issued additional authoritative accounting guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. We adopted this guidance for the first quarter of 2013. The implementation of this additional guidance did not affect our results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. See Note 6 - Derivative Financial Instruments for the required additional disclosures.
Presentation of an Unrecognized Tax Benefit
In July 2013, FASB issued additional authoritative accounting guidance to provide clarity for the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The objective of this guidance is to eliminate diversity in practice related to the presentation of certain unrecognized tax benefits. It requires entities to present an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward to the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is available under the tax law. Currently, any unrecognized tax benefit is recorded in “Other deferred credits and liabilities” on our balance sheet. After this guidance becomes effective, any unrecognized tax benefit will be recorded in “Accumulated deferred income taxes, net” as a reduction to the deferred tax assets for net operating loss and tax credit carryforwards on our balance sheet. To the extent that an unrecognized tax benefit exceeds these carryforwards, the excess would continue to be recorded in “Other deferred credits and liabilities” on our consolidated balance sheet, consistent with current authoritative accounting guidance. The amended guidance will not affect our results of operations or liquidity, as this guidance is presentation-related only. This guidance will be effective for us beginning in the first quarter of 2014.

Assets_Held_for_Sale

Assets Held for Sale	9 Months Ended
	Sep. 30, 2013
Property, Plant and Equipment Assets Held-for-sale Disclosure [Abstract]	'
ASSETS HELD FOR SALE	'
	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 gas-fired energy centers, (iv) the obligations relating to Ameren's single-employer pension and postretirement benefit plans, and (v) the deferred tax positions associated with Ameren's ownership of these retained assets and liabilities, to New AER. IPH will acquire all of the equity interests in New AER.
	Ameren will retain the 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 $32 million at September 30, 2013. We will also retain the estimated $15 million asset at September 30, 2013, relating to the overfunded status of one of EEI’s postretirement plans.
	Ameren will retain our Meredosia and Hutsonville energy centers, which are idle and had an immaterial property and plant asset balance as of September 30, 2013. Ameren will also retain AROs associated with these energy centers, estimated at $27 million as of September 30, 2013. With the exception of the Grand Tower ARO, which will be assumed by the third-party buyer of the Grand Tower energy center as discussed below, we will retain all of our other AROs. Additionally, Ameren will retain our tax payable to Ameren Illinois, which was $43 million as of September 30, 2013.
	Ameren’s retention of our liabilities for pension and postretirement benefit obligations relating to Ameren’s plans, the idle 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 Ameren’s divestiture of New AER to 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 of September 30, 2013, we had $80 million in federal income tax net operating loss carryforwards and $1 million in federal income tax credit carryforwards. If Ameren were to retain ownership of us, these carryforwards are expected to offset income tax liabilities into 2016, consistent with the tax allocation agreement with Ameren. If Ameren’s divestiture of New AER to IPH is completed, any unused portion of the net operating loss and tax credit carryforwards described above will decrease. Additionally, all liabilities, obligations and rights between us and Ameren and its non-AER affiliates under the tax allocation agreement will terminate at the closing date as to all past, present and future taxable periods.
	As described in more detail below under “Amended Put Option Agreement, Asset Purchase Agreement and Guaranty,” as a condition to the transaction agreement, we exercised 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 and received cash proceeds of $137.5 million. If these gas-fired energy centers are subsequently sold to a third-party and Medina Valley receives proceeds within two years of the closing of the New AER divestiture, Medina Valley will pay us any proceeds from such sale, net of taxes and other expenses, in excess of the amount it previously paid, which totaled $137.5 million.
	Our $825 million of senior notes will remain outstanding following the closing of the transaction agreement 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 divestiture to IPH requires FERC and FCC approvals. In October 2013, FERC issued an order approving Ameren’s divestiture of New AER and our sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. The FCC approval was received in August 2013. Separately, as a condition to IPH’s obligation to complete the New AER transaction, the Illinois Pollution Control Board must approve the transfer to IPH of, or otherwise approve a variance in favor of IPH on the same material terms as, AER’s variance of the Illinois MPS. In May 2013, AER and IPH filed a transfer request with the Illinois Pollution Control Board, which was subsequently denied by the board on procedural grounds. On July 22, 2013, IPH, AER, and Medina Valley, as current and future owners of the coal-fired energy centers, filed a request for a variance with the Illinois Pollution Control Board seeking materially the same relief as the existing AER variance. The Illinois Pollution Control Board has until late November 2013 to issue a decision. See Note 8 - Commitments and Contingencies for additional information. Ameren’s and IPH’s obligation to complete the transaction is also subject to other customary closing conditions, including the material accuracy of each company’s representations and warranties and the compliance, in all material respects, with each company’s covenants. The transaction agreement contains customary representations and warranties of Ameren and IPH, including representations and warranties of Ameren with respect to the business being sold. The transaction agreement also contains customary covenants of Ameren and IPH, including the covenant of Ameren that AER will be operated in the ordinary course prior to the closing.
	Ameren expects the closing of the New AER divestiture to IPH will occur in the fourth quarter of 2013. If the closing does not occur on or before March 14, 2014, either party may elect to terminate the transaction agreement if the inability to close the transaction by such date is not the result of the failure of the terminating company to fulfill any of its obligations under the transaction agreement.
	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. In exchange for entering into the put option agreement, we paid AERG a put option premium of $2.5 million. We recorded less than $1 million in amortization expense during both the three month and nine month periods ended September 30, 2012. We recorded the remaining $1.5 million in amortization expense during the first quarter of 2013 upon the option being exercised.
	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 result, on March 14, 2013, we received an initial payment of $100 million from Medina Valley with an offset to “Deposit received from affiliate for pending asset sale,” in accordance with the terms of the amended put option agreement. 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 dated March 14, 2013. The asset purchase agreement provided that we would receive an additional payment upon closing of the asset purchase agreement to the extent the average fair market value for the Elgin, Gibson City, and Grand Tower gas-fired energy centers, as determined based on three independent appraisals, exceeded the $100 million initial payment we received from Medina Valley. Along with Medina Valley, we engaged three independent appraisers to conduct fair market valuations of the Elgin, Gibson City, and Grand Tower gas-fired energy centers. The average fair market value pursuant to such appraisals for the Elgin, Gibson City, and Grand Tower gas-fired energy centers was $137.5 million, which was greater than the original fair value estimate of $133 million. Therefore, after receipt of FERC approval and upon closing of the asset purchase agreement in October 2013, we received an additional payment of $37.5 million from Medina Valley. We advanced the additional $37.5 million we received into the non-state-regulated subsidiary money pool. Ameren’s guaranty to Medina Valley expired upon the closing of the asset purchase agreement.
	The transaction agreement with IPH provides that if the Elgin, Gibson City, and Grand Tower gas-fired energy centers are subsequently sold and Medina Valley receives proceeds within two years of the closing of the New AER divestiture, 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, which totaled $137.5 million.
	Medina Valley has entered into an agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. This agreement requires a portion of the purchase price to be held in escrow until the two year anniversary of the closing of the sale to fund certain indemnity obligations, if any, of Medina Valley. Ameren expects the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital to close by the end of 2013, subject to receipt of FERC and other regulatory approvals. If this sale is completed, Medina Valley could pay us after-tax net proceeds of up to an additional $15 million based on the maximum escrow amount that could ultimately be released, projected working capital adjustments, and projected transaction expenses.
	In August 2013, the Illinois Municipal Electric Agency, which is a wholesale customer of Marketing Company, filed a lawsuit in the United States District Court for the Central District of Illinois, against Marketing Company alleging that the removal of certain assets that were related to the amended put option agreement from the parties’ contract schedules without the customer’s consent constituted a breach of contract. In addition, the lawsuit alleges that Genco and AERG failed to recognize certain asset impairments that the Illinois Municipal Electric Agency alleges have occurred and which the Illinois Municipal Electric Agency claims would, if recognized, reduce the billings to the Illinois Municipal Electric Agency. The lawsuit also makes certain other claims that the proposed divestiture would result in a breach of the parties’ contract. If the court ultimately agrees with the Illinois Municipal Electric Agency’s claim that asset impairments should have been recognized, we would receive less revenue from Marketing Company under the PSA. During the third quarter of 2013, the Illinois Municipal Electric Agency began depositing into an escrow account the portion of its monthly billings being disputed. As of September 30, 2013, the Illinois Municipal Electric Agency had deposited $5 million into escrow. We have not recognized in earnings our portion of the escrowed amount, which totaled $4 million for the third quarter of 2013.
	We determined that the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers first qualified for held for sale presentation as of March 14, 2013 and continued to qualify as of September 30, 2013. As of December 31, 2012, these energy centers did not meet the criteria to be classified as held for sale as we did not consider it probable at that time that a disposition of an energy center would occur 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 gas-fired 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 September 30, 2013, and December 31, 2012:
		30-Sep-13		31-Dec-12
	Assets held for sale
	Materials and supplies	$	5	$	12
	Mark-to-market derivative assets	—		4
	Property and plant, net	147		348
	Total assets held for sale	$	152	$	364
	Liabilities held for sale
	Accounts and wages payable	$	3	$	9
	Taxes accrued	2		3
	Mark-to-market derivative liabilities	—		3
	Asset retirement obligations	10		10
	Total liabilities held for sale	$	15	$	25
	As the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers continued to meet the held for sale criteria at September 30, 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. 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 charge decreased by $5 million during the three months ended June 30, 2013, as the carrying value of the Elgin, Gibson City, and Grand Tower gas-fired energy centers decreased primarily as a result of derivative market value losses. The impairment charge decreased by an additional $5 million during the three months ended September 30, 2013, primarily as a result of the increase in the fair value of the disposal group based on the average of the three independent appraisers’ valuation of the Elgin, Gibson City, and Grand Tower gas-fired energy centers. We recorded a cumulative pretax charge to earnings of $197 million for the nine months ended September 30, 2013, to reflect the impairment of the Elgin, Gibson City, and Grand Tower gas-fired energy centers. The 2013 impairment recorded was primarily related to the Gibson City and Grand Tower gas-fired energy centers as the Elgin energy center was previously impaired under held and used accounting guidance during the fourth quarter of 2012. The 2013 impairment charge to earnings was recorded as an impairment of “Property and Plant, net” within the components of assets held for sale shown above as of September 30, 2013, and “Assets held for sale and impairment adjustments” in our consolidated statement of income (loss) and comprehensive income (loss) for the three and nine months ended September 30, 2013. During the nine months ended September 30, 2013, we recorded a $77 million income tax benefit as a result of the impairment.
	These assets and liabilities held for sale 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.

Related_Party_Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2013
Related Party Transactions [Abstract]	'
RELATED PARTY TRANSACTIONS	'
	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 to us from Ameren Services 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 and nine months ended September 30, 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 Liquidity of this report.
				Three Months				Nine months
	Agreement	Income Statement Line Item		2013		2012		2013		2012
	Genco and EEI power supply and other agreements with Marketing Company	Operating Revenues - Electric	$	219	$	217	$	557	$	603
	Natural gas sales to Medina Valley(a)	Operating Revenues - Electric		—		—		—		1
	Services provided to AER affiliates	Operating Revenues - Other		1		(b)		5		(b)
	Total Operating Revenues		$	220	$	217	$	562	$	604
	Ameren Missouri gas transportation agreement	Fuel	$	(b)	$	(b)	$	1	$	1
	EEI power supply agreement with Marketing Company	Purchased Power	$	47	$	(b)	$	65	$	1
	Ameren Services support services agreement	Other Operations and Maintenance	$	2	$	7	$	8	$	17
	Money pool borrowings (advances)	Interest (Charges) Income	$	(b)	$	(b)	$	(b)	$	(b)
	(a)	Natural gas sold at fair value.
	(b)	Amount less than $1 million.

ShortTerm_Debt_and_Liquidity

Short-Term Debt and Liquidity	9 Months Ended
	Sep. 30, 2013
Line of Credit Facility [Abstract]	'
SHORT-TERM DEBT AND LIQUIDITY	'
	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 and received an initial payment of $100 million. On October 11, 2013, we completed the sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley and received an additional payment of $37.5 million. We advanced these payment amounts to the non-state-regulated subsidiary money pool. Based on current market conditions, operating assumptions, money pool advances, and cash on hand, we expect to have sufficient liquidity over the next twelve months to operate our business. See Note 2 - Assets Held for Sale for additional information regarding the amended put option agreement.
	Money Pool
	Ameren has a non-state-regulated subsidiary money pool to coordinate and to provide short-term cash and working capital to its non-state-regulated subsidiaries. As further discussed in Note 5 - Long-term Debt, we have the ability, subject to Ameren parent company authorization and Ameren (parent) borrowing sublimits, 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. Ameren (parent) has a $500 million and a $300 million borrowing sublimit under its $1.0 billion and $1.1 billion multiyear senior unsecured credit agreements, respectively. 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.
	See Note 3 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements for the three and nine months ended September 30, 2013, and 2012, and Note 5 - Long-Term Debt for borrowing restrictions.

LongTerm_Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2013
Long-term Debt, Unclassified [Abstract]	'
LONG-TERM DEBT	'
	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.” 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 12 months ended and as of September 30, 2013:
		Required Ratio	Actual Ratio
	Interest coverage ratio- restricted payment(a)	≥1.75	1.05
	Interest coverage ratio- additional indebtedness(b)	≥2.50	1.05
	Debt-to-capital ratio- additional indebtedness (b)	≤60%	51	%
	(a)	As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.
	(b)	Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.
	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 2.5 or if our debt-to-capital ratio is greater than 60%. Beginning in 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. In December 2012, Ameren announced it intended to, and it was probable that it would, exit its Merchant Generation business, of which we are a part, as Ameren determined that business was no longer a core component of its future business strategy. If Ameren does not complete its divestiture of New AER, Ameren has indicated it will continue to reduce, and ultimately eliminate, its financial support of the Merchant Generation business until its ultimate exit from the business is complete. We will seek to fund operations internally and therefore seek not to rely on financing from Ameren.
	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.
	As shown in the table above, under the provisions of Genco’s indenture, dividends cannot be paid unless the actual interest coverage ratio for the most recently ended four fiscal quarters is greater than 1.75, which was not achieved during the four fiscal quarters ending September 30, 2013. Additionally, the interest coverage ratios projected by management for each of the subsequent four six-month periods must be greater than 1.75. Based on projections as of September 30, 2013, we do not believe 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 March 31, 2014, September 30, 2014, March 31, 2015, or September 30, 2015. As a result, we were restricted from paying dividends as of September 30, 2013, and we expect to be unable to pay dividends through at least September 30, 2016.
	Off-Balance-Sheet Arrangements
	At September 30, 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.

Derivative_Financial_Instrumen

Derivative Financial Instruments	9 Months Ended
	Sep. 30, 2013
Derivative Instrument Detail [Abstract]	'
DERIVATIVE FINANCIAL INSTRUMENTS	'
	DERIVATIVE FINANCIAL INSTRUMENTS
	We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, 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.
	The following table presents open gross commodity contract volumes by commodity type as of September 30, 2013, and December 31, 2012:
		Quantity (in millions)
	Commodity	Accrual & NPNS						Other
		Contracts(a)						Derivatives(b)
		2013			2012			2013			2012
	Coal (in tons)	26			30			3			5
	Fuel oils (in gallons)(c)	(d)			(d)			26			40
	Natural gas (in mmbtu)(e)	(d)			(d)			1			42
	Power	(f)			(f)			—			—
	(a)	Accrual contracts include commodity contracts that do not qualify as derivatives. As of September 30, 2013, these contracts ran through December 2017 for coal.
	(b)	As of September 30, 2013, these contracts ran through December 2015, October 2016, and April 2015 for coal, fuel oils, and natural gas, respectively.
	(c)	Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.
	(d)	Not applicable.
	(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 September 30, 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		1				2
		Other assets		—				1
	Natural gas	Assets held for sale		—				4
		Total assets		$	2			$	8
	Derivative liabilities not designated as hedging instruments
	Commodity contracts:
	Coal	MTM derivative liabilities		$	5			$	7
		Other deferred credits and liabilities		1				3
	Fuel oils	MTM derivative liabilities		—				1
		Other deferred credits and liabilities		—				1
	Natural gas	Liabilities held for sale		—				3
		Total liabilities		$	6			$	15
	The cumulative amount of pretax net losses on interest rate derivative instruments in accumulated OCI was $6 million and $7 million, respectively, as of September 30, 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. The pretax net loss reclassified from accumulated OCI into “Interest charges” was $1 million and $1 million for three and nine months ended September 30, 2013 and less than $1 million and less than $1 million for the three and nine months ended September 30, 2012. 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. 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 September 30, 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)		$	2		$	2		$	—		$	—
	Liabilities:
	Commodity contracts eligible to be offset(b)		$	6		$	2		$	—		$	4
	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 is included in the “Other current liabilities” and “Other deferred credits and liabilities” lines in the balance sheet. Cash collateral posted reduces gross liability balances and is included in the “Other current assets” and “Other assets” lines in the balance sheet.
	(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 September 30, 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				Commodity				Financial				Oil and Gas			Total
	Producers				Marketing				Companies				Companies
					Companies
2013(a)	$	—			$	1			$	—			$	1		$	2
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 September 30, 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 September 30, 2013, and December 31, 2012:
	Coal				Commodity				Financial				Oil and Gas			Total
	Producers				Marketing				Companies				Companies
					Companies
2013(a)	$	—			$	1			$	—			$	1		$	2
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 September 30, 2013, and December 31, 2012, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements assuming (1) the credit risk-related contingent features underlying these agreements were triggered on September 30, 2013, or December 31, 2012, respectively, and (2) those counterparties with rights to do so requested collateral:
	Aggregate Fair Value of				Cash				Potential Aggregate Amount of
	Derivative Liabilities(a)				Collateral Posted				Additional Collateral Required(b)
2013(c)	$	34			$	—			$	32
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 netting effects of such agreements.
(c)	Includes amounts classified as held for sale.
Other Derivatives
The following table represents the net change in market value for derivatives not designated as hedging instruments for the three and nine months ended September 30, 2013, and 2012:
		Location of Gain (Loss)		Gain (Loss) Recognized
		Recognized in Income		in Income
				Three Months								Nine Months
				2013				2012				2013			2012
Coal		Operating Expenses - Fuel		$	—			$	—			$	4		$	(8	)
Fuel oils		Operating Expenses - Fuel		2				5				—			(5		)
Natural gas(a)		Operating Expenses - Fuel		—				(1		)		(1		)	3
Power		Operating Revenues		(1		)		—				—			—
		Total		$	1			$	4			$	3		$	(10	)
(a)	Includes amounts classified as held for sale.

Fair_Value_Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
FAIR VALUE MEASUREMENTS	'
	FAIR VALUE MEASUREMENTS
	Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:
	Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives.
	Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets 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.
	There were no financial assets and liabilities classified as Level 3 in the fair value hierarchy as of September 30, 2013. 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 as of December 31, 2012:
		Fair Value									Weighted
		Assets			Liabilities			Valuation Technique	Unobservable Input	Range	Average
	Level 3 Derivative asset and liability - commodity contracts(a):
	Fuel oils	$	1		$	—		Discounted cash flow	Escalation rate(%)(b)	.21 - .68	0.59
									Counterparty credit risk(%)(c)(d)	.12 - 1	1
									Genco credit risk(%)(c)(d)	31-Mar	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 nine months ended September 30, 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 September 30, 2013, and December 31, 2012, respectively.
	The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of September 30, 2013, and December 31, 2012:
				Quoted Prices in				Significant Other				Significant Other				Total
				Active Markets for				Observable				Unobservable
				Identical Assets				Inputs				Inputs
				or Liabilities				(Level 2)				(Level 3)
				(Level 1)
	2013
	Assets:
		Derivative assets - commodity contracts(a):
		Coal		$	1			$	—			$	—			$	1
		Fuel oils		1				—				—				1
		Total assets		$	2			$	—			$	—			$	2
	Liabilities:
		Derivative liabilities - commodity contracts(a):
		Coal		$	6			$	—			$	—			$	6
		Total liabilities		$	6			$	—			$	—			$	6
	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 for the three and nine months ended September 30, 2013, and 2012:
		Net derivative commodity contracts
		Three Months Ended								Nine Months Ended
			2013				2012				2013				2012
	Fuel oils:
	Beginning balance		$	—			$	1			$	1			$	1
	Realized and unrealized gains (losses):
	Included in earnings(a)		1				—				—				—
	Total realized and unrealized gains (losses)		1				—				—				—
	Purchases		—				(1		)		—				—
	Settlements		(1		)		—				(1		)		—
	Transfers out of Level 3		—				1				—				—
	Ending balance		$	—			$	1			$	—			$	1
	Change in unrealized gains (losses) related to assets/liabilities held at September 30		$	—			$	—			$	—			$	—
Power:
Beginning balance		$	1			$	—			$	—			$	—
Realized and unrealized gains (losses):
Included in earnings		—				—				—				—
Total realized and unrealized gains (losses)		—				—				—				—
Purchases		—				—				(19		)		—
Sales		—				—				21				—
Settlements		(1		)		—				(2		)		—
Ending balance		$	—			$	—			$	—			$	—
Change in unrealized gains (losses) related to assets/liabilities held at September 30		$	—			$	—			$	—			$	—
(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 and nine months ended September 30, 2013, and 2012. Any reclassifications are 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 and nine months ended September 30, 2013, and 2012, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. For the three and nine months ended September 30, 2013, there were no transfers between Level 1 and Level 3 related to derivative commodity contracts. For the three months ended September 30, 2012, there were fuel oil transfers out of Level 3 into Level 1 of $1 million. For the nine months ended September 30, 2012, there were no transfers between Level 1 and Level 3.
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 September 30, 2013, and December 31, 2012:
	September 30, 2013								December 31, 2012
	Carrying Amount				Fair Value				Carrying Amount				Fair Value
Long-term debt	$	824			$	639			$	824			$	618

Commitments_and_Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]	'
COMMITMENTS AND CONTINGENCIES	'
	COMMITMENTS AND CONTINGENCIES
	We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, 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 September 30, 2013, total other obligations related to the procurement of coal and natural gas, among other agreements, were $383 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 and renew approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) require release prevention plans and emergency response procedures.
	In addition to existing environmental laws and regulations, including the Illinois MPS that applies to AER’s coal-fired energy centers in Illinois, the EPA is developing regulations that will have a significant impact on the electric 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 from new energy centers; revised national ambient air quality standards for fine particulates, SO2, and NOx emissions; the CSAPR, which would have required further reductions of SO2 emissions and NOx 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 NOx emissions from new sources; new effluent standards applicable to discharges from steam-electric generating units; and new regulations under the Clean Water Act that could require significant capital expenditures such as new water intake structures or cooling towers at our energy centers. The EPA is expected to propose CO2 limits for existing fossil fuel-fired electric generation units in the future. These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia Circuit in August 2012. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and increased operating costs over the next five to ten years. Compliance with these environmental laws and regulations could be prohibitively expensive. If they are, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.
	The estimates in the 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 MATS and of the EPA's proposed regulation for CCR as of September 30, 2013. In addition, the estimates assume that CCR will continue to be regarded as nonhazardous. The estimates do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures or the impact of the effluent standards applicable to steam-electric generating units that the EPA proposed in April 2013, as the technology requirements ultimately to be selected in these final rules are not yet known. The estimates shown in the table below could change significantly depending upon a variety of factors including:
	•	Ameren’s divestiture of its Merchant Generation business, of which we are a part;
	•	additional or modified federal or state requirements;
	•	further regulation of greenhouse gas emissions;
	•	revisions to CAIR or reinstatement of CSAPR;
	•	delays or accelerations of rulemaking and implementation by the EPA or state agencies;
	•	new national ambient air quality standards, new standards intended to achieve national ambient air quality standards or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions;
	•	additional or new rules governing air pollutant transport;
	•	regulations or requirements under the Clean Water Act regarding cooling water intake structures or effluent standards;
	•	finalized regulations classifying CCR as being hazardous or imposing additional requirements on the management of CCR;
	•	new limitations or standards under the Clean Water Act applicable to discharges from steam-electric generating units;
	•	new technology;
	•	changes in expected power prices;
	•	variations in costs of material or labor; and
	•	alternative compliance strategies or investment decisions.
		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 reflect the increased cost for environmental compliance.
	The following sections describe the more significant environmental laws and rules that affect or could affect our operations.
	Clean Air Act
	Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR). The CAIR requires 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 NOx emissions, and ozone season NOx emissions.
	In December 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the CAIR to the EPA for further action to remedy the rule's flaws, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR. In August 2012, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that vacated the CSAPR in its entirety, finding that the EPA exceeded its authority in imposing the CSAPR's emission limits on states. In March 2013, the EPA and certain environmental groups filed an appeal of the Court of Appeals’ remand of CSAPR to the United States Supreme Court. The United States Supreme Court has agreed to consider the appeal and is expected to issue a ruling on the appeal during its current term, which ends in June 2014. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the United States Supreme Court overturns the decision to vacate the CSAPR.
	In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and for the first time require continuous monitoring systems for hydrogen chloride, mercury, and particulate matter. The MATS do not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant; however in certain cases, emission compliance can be achieved by averaging emissions from similar electric generating units at the same power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016.
	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 NOx emissions. States are required to demonstrate compliance with the rule 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 control requirements for power plants by 2020. We continue to assess the impacts of these new standards.
	In July 2013, the EPA issued a final rule designating portions of the United States, including parts of Illinois, as nonattainment for the national ambient air quality standard for SO2. The designations became effective in October 2013, and the states must develop plans in the next 18 months to reduce emissions so that they can achieve the ambient air quality standards within five years. We are assessing the impact of this designation.
	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.
	See Note 2 - Assets Held for Sale for additional information regarding the divestiture of New AER and a request filed with the Illinois Pollution Control Board for a variance in favor of IPH on the same material terms as the Illinois MPS variance granted to AER in September 2012.
	Under the MPS, AER is required to reduce mercury, NOx and SO2 emissions with declining limits that started in 2009 for mercury and in 2010 for NOx and SO2. The final NOx 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, NOx, 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 NOx 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 NOx allowances. We expect to have adequate allowances for 2013 to avoid needing to make external purchases to comply with these programs.
	Greenhouse Gas Regulation
	State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions. Potential impacts from any such legislation or regulation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2.
	In December 2009, the EPA issued its “endangerment finding” under the Clean Air Act, which stated that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.
	Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA issued the “Tailoring Rule,” which established new higher emission thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permit upon renewal. Currently, 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 to address greenhouse gas emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld the Tailoring Rule. Industry groups and a coalition of states filed petitions in April 2013 requesting that the United States Supreme Court review the circuit court’s decision upholding the Tailoring Rule. In October 2013, the United States Supreme Court granted the petition agreeing to consider whether the Clean Air Act authorizes the EPA to regulate emissions of greenhouse gases from stationary sources, including power plants, as a result of the EPA’s determination to regulate greenhouse gas emissions from motor vehicles. A ruling is expected in 2014.
	In June 2013, the Obama Administration announced that it had directed the EPA to set CO2 emissions standards for both new and existing power plants. The EPA proposed revised CO2 emissions regulations for new electricity generating units in September 2013. The proposed standards would establish separate emissions limits for new natural gas-fired plants and new coal-fired plants. In addition, the Obama Administration had directed the EPA to propose a CO2 emissions standard for existing power plants by June 2014 and to finalize such standard by June 2015. Currently, we are unable to predict the outcome or impacts of such future regulations.
	Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address alleged damages resulting from greenhouse gas emissions. In March 2012, the United States District Court for the Southern District of Mississippi dismissed the Comer v. Murphy Oil lawsuit, which alleged that CO2 emissions from several industrial companies, including us, created atmospheric conditions that intensified Hurricane Katrina, thereby causing property damage. In May 2013, the dismissal of the lawsuit was affirmed by the United States Court of Appeals for the Fifth Circuit.
	Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. These compliance costs could be prohibitive at some of our energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets. As a result, mandatory limits on the emission of greenhouse gases could have a material adverse impact on our results of operations, financial position, and liquidity.
	NSR and Clean Air Litigation
	The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications. The EPA's inquiries focus on whether projects performed at power plants triggered various permitting requirements and the installation of pollution control equipment.
	Commencing in 2005, 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. A recent decision by the United States Court of Appeals for the Seventh Circuit held that similar claims older than five years were barred by the statute of limitations. If not reversed or overturned, this decision may provide an additional defense to the allegations in the Newton energy center Notice of Violation. We have included $3 million in “Other current liabilities” on our consolidated balance sheet as of September 30, 2013, relating to this loss contingency. We are unable to predict the outcome of this matter.
	Ultimate resolution of these matters could have a material adverse impact on our 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 November 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. The final rule could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers or extensive modifications to the cooling water systems at our energy centers.
	In April 2013, the EPA announced its proposal to revise the effluent limitation guidelines applicable to steam electric generating units under the Clean Water Act. Effluent limitation guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The proposed revision targets wastewater streams associated with fluegas desulfurization (i.e. scrubbers), fly ash, bottom ash, fluegas mercury control, CCR leachate from landfills and impoundments, nonchemical metal cleaning, and gasification of fuels. The EPA’s proposal identifies several alternatives for addressing these waste streams, including best management practices for CCR impoundments. The EPA’s proposed rule raised several compliance options that would prohibit effluent discharges of certain, but not all, waste streams and impose more stringent limitations on certain components in wastewater discharges from power plants. If enacted as proposed, we would be subject to the revised limitations beginning as early as July 1, 2017, but no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impact on our operations if enacted as proposed. The EPA expects to issue a final rule in 2014.
	Environmental Claims
	As part of the transfer of generation assets 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 any environmental liabilities associated with the Meredosia and Hutsonville energy centers. The agreement will also specify that any 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 regarding Ameren’s divestiture of New AER.
Ash Management
There has been activity at both state and federal levels regarding additional regulation of CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric generating units would apply to ash ponds and CCR management and that it intended to align this proposal with the CCR rules proposed in May 2010. Additionally, in January 2010, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. 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. AER filed a proposed rulemaking with the Illinois Pollution Control Board which, if approved, would provide for the systematic and eventual closure of ash ponds. In October 2013, the Illinois EPA filed a proposed rulemaking with the Illinois Pollution Control Board. AER has stayed its rulemaking efforts to allow the Illinois EPA proposed rulemaking to proceed. The rulemaking process could take several years to complete. During the first quarter of 2013, we revised our ARO fair value estimates relating to ash ponds to reflect expected retirement dates. See Note 1 - Summary of Significant Accounting Policies for additional information related to our asset retirement obligations.
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 pursuant to the transaction agreement in which Ameren agrees to divest New AER to IPH. The amended plant transfer agreement will provide that Ameren Illinois will continue to retain asbestos exposure-related liabilities for claims arising or existing from activities prior to the transfer of the ownership of the CIPS energy centers to us. IPH will be responsible for any asbestos-related claims arising from activities that occur after IPH takes ownership of New AER. Any asbestos-related claims arising solely from activities post transfer of the energy centers from CIPS 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 is not a party to the plant transfer agreement with Ameren Illinois discussed above. As of September 30, 2013, six 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
Beginning in the second quarter of 2010 through 2011, we claimed Illinois sales and use tax exemptions and credits for purchase transactions related to our generation operations. During the second quarter of 2013, we resolved a tax dispute with the Illinois Department of Revenue relating to these sales and use tax exemptions and credits for all open periods related to this issue with a $5 million payment to the Illinois Department of Revenue. This charge was recorded within “Operating Expenses - Fuel” on Genco’s consolidated statement of income (loss) and comprehensive income (loss) during the nine months ended September 30, 2013.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
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 the 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 Ameren 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 pre-tax noncash long-lived asset impairment charge of $70 million 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, we 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, which Ameren expects will close during the fourth quarter of 2013. Immediately prior to Ameren’s entry into the transaction agreement with IPH, on March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million with respect to the sale of our Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. On October 11, 2013, Ameren received FERC approval for the divestiture of New AER to IPH and our sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. Immediately after receipt of FERC approval, we completed the sale of these gas-fired energy centers to Medina Valley and received additional cash proceeds of $37.5 million. Medina Valley has entered into an agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. Ameren expects this third-party sale of these gas-fired energy centers to close by the end of 2013, subject to FERC and other regulatory approvals. See Note 2 - Assets Held for Sale for additional information.
	We determined that the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers first qualified for held for sale presentation beginning March 14, 2013. 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 September 30, 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.
	Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.
Uncertain Tax Positions	'
	The amount of unrecognized tax benefits as of September 30, 2013, was $5 million. Unrecognized tax benefits are included in “Other deferred credits and liabilities” on our consolidated balance sheet. This amount of unrecognized tax benefits as of September 30, 2013, would have no impact on the effective tax rate, if recognized.
	During the three months ended September 30, 2013, unrecognized tax benefits related to the deductibility of expenditures to maintain, replace, or improve steam or electric power generation property were reduced by $4 million, with an offset to “Accumulated deferred income taxes, net”. This was the result of recent Internal Revenue Service guidance establishing new rules for the amount and timing of these deductions.
	We are included in Ameren’s federal income tax return. Ameren’s federal income tax returns for the years 2007 through 2011 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2012 is currently under examination.
	It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the next 12 months for the years 2007 through 2011. This settlement, which is primarily related to uncertain tax positions for research tax deductions, is expected to result in a decrease in uncertain tax benefits of $5 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 Internal Revenue Service 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 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	'
	Our 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 on the consolidated balance sheet.
Asset Retirement Obligations	'
	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 idle Meredosia and Hutsonville energy centers, which were estimated at $27 million as of September 30, 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 “Liabilities held for sale” as of September 30, 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 October 2013 sale of the Grand Tower energy center to Medina Valley and the transfer at the closing of Ameren’s New AER divestiture 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.
	Under the terms of the transaction agreement to divest New AER to IPH, 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 $32 million at September 30, 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 at September 30, 2013.
Accounting and Reporting Developments	'
	The following is a summary of recently adopted authoritative accounting guidance, as well as guidance issued but not yet adopted, 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 required 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 amended guidance 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 and derivatives. For the three and nine months ended September 30, 2013, the pension and other postretirement plan and derivative activity were immaterial.
	Disclosures about Offsetting Assets and Liabilities
	In December 2011, FASB issued additional authoritative accounting guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. We adopted this guidance for the first quarter of 2013. The implementation of this additional guidance did not affect our results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. See Note 6 - Derivative Financial Instruments for the required additional disclosures.
	Presentation of an Unrecognized Tax Benefit
	In July 2013, FASB issued additional authoritative accounting guidance to provide clarity for the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The objective of this guidance is to eliminate diversity in practice related to the presentation of certain unrecognized tax benefits. It requires entities to present an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward to the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is available under the tax law. Currently, any unrecognized tax benefit is recorded in “Other deferred credits and liabilities” on our balance sheet. After this guidance becomes effective, any unrecognized tax benefit will be recorded in “Accumulated deferred income taxes, net” as a reduction to the deferred tax assets for net operating loss and tax credit carryforwards on our balance sheet. To the extent that an unrecognized tax benefit exceeds these carryforwards, the excess would continue to be recorded in “Other deferred credits and liabilities” on our consolidated balance sheet, consistent with current authoritative accounting guidance. The amended guidance will not affect our results of operations or liquidity, as this guidance is presentation-related only. This guidance will be effective for us beginning in the first quarter of 2014.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
Equity Changes Attributable to Noncontrolling Interest	'
	A reconciliation of the equity changes attributable to our noncontrolling interests for the three and nine months ended September 30, 2013, and 2012, is shown below:
		Three Months							Nine Months
		2013				2012			2013				2012
	Noncontrolling interest, beginning of period	$	8			$	3		$	8			$	7
	Net loss attributable to noncontrolling interest	—				(2		)	—				(6		)
	Other comprehensive income attributable to noncontrolling interest(a)	—				9			—				9
	Noncontrolling interest, end of period	$	8			$	10		$	8			$	10
	(a)	Represents the noncontrolling interest of EEI’s pension and other postretirement benefit plan activity, net of income taxes of $-, $6, $-, and $6, respectively.
Schedule of Asset Retirement Obligations	'
	The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the nine months ended September 30, 2013:
	Balance at December 31, 2012	$	59
	Liabilities settled	(a)
	Accretion	3
	Change in estimates(b)	6
	Balance at September 30, 2013	$	68
	(a)	Less than $1 million.
	(b)	We changed our estimate due to updated retirement dates for certain CCR storage facilities during the first quarter of 2013. See Note 8 - Commitments and Contingencies for additional information regarding this change in estimate.
Components Of Net Periodic Benefit Cost	'
	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 the three and nine months ended September 30, 2013, and 2012:
		Pension Benefits(a)															Postretirement Benefits(a)
		Three Months							Nine Months								Three Months						Nine Months
		2013				2012			2013				2012				2013			2012			2013			2012
	Service cost	$	1			$	1		$	3			$	3			$	—		$	1		$	1		$	3
	Interest cost	2				3			7				8				1			1			3			4
	Expected return on plan assets	(3		)		(3		)	(10		)		(9		)		(1		)	(1		)	(4		)	(4		)
	Amortization of:
	Prior service cost (benefit)	—				—			—				—				(2		)	—			(6		)	—
	Actuarial loss	2				1			6				3				1			1			3			3
	Curtailment loss	—				2			—				2				—			—			—			—
	Net periodic benefit cost	$	2			$	4		$	6			$	7			$	(1	)	$	2		$	(3	)	$	6
	(a)	Includes amounts for our participation in Ameren’s single-employer plans and the cost of EEI’s plans.
Summary of Allocated Net Period Benefit Costs	'
	We are allocated a share of the net periodic benefit costs for pension and postretirement benefits for Ameren Services employees doing work on our behalf. The following table presents these costs for the three and nine months ended September 30, 2013, and 2012:
			Pension Benefits										Postretirement Benefits
			Three Months					Nine Months					Three Months				Nine Months
			2013			2012		2013		2012			2013		2012		2013		2012
	Allocated benefit costs	$	1		$	(a)	$	2	$	1		$	(a)	$	(a)	$	(a)	$	(a)
	(a)	Less than $1 million.

Assets_Held_for_Sale_Tables

Assets Held for Sale (Tables)	9 Months Ended
	Sep. 30, 2013
Property, Plant and Equipment Assets Held-for-sale Disclosure [Abstract]	'
Disclosure of Long Lived Assets Held-for-sale	'
	The following table presents the components of assets and liabilities held for sale on our consolidated balance sheet at September 30, 2013, and December 31, 2012:
		30-Sep-13		31-Dec-12
	Assets held for sale
	Materials and supplies	$	5	$	12
	Mark-to-market derivative assets	—		4
	Property and plant, net	147		348
	Total assets held for sale	$	152	$	364
	Liabilities held for sale
	Accounts and wages payable	$	3	$	9
	Taxes accrued	2		3
	Mark-to-market derivative liabilities	—		3
	Asset retirement obligations	10		10
	Total liabilities held for sale	$	15	$	25

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2013
Related Party Transactions [Abstract]	'
Schedule of Related Party Transactions	'
	The following table presents the impact of related party transactions for the three and nine months ended September 30, 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 Liquidity of this report.
				Three Months				Nine months
	Agreement	Income Statement Line Item		2013		2012		2013		2012
	Genco and EEI power supply and other agreements with Marketing Company	Operating Revenues - Electric	$	219	$	217	$	557	$	603
	Natural gas sales to Medina Valley(a)	Operating Revenues - Electric		—		—		—		1
	Services provided to AER affiliates	Operating Revenues - Other		1		(b)		5		(b)
	Total Operating Revenues		$	220	$	217	$	562	$	604
	Ameren Missouri gas transportation agreement	Fuel	$	(b)	$	(b)	$	1	$	1
	EEI power supply agreement with Marketing Company	Purchased Power	$	47	$	(b)	$	65	$	1
	Ameren Services support services agreement	Other Operations and Maintenance	$	2	$	7	$	8	$	17
	Money pool borrowings (advances)	Interest (Charges) Income	$	(b)	$	(b)	$	(b)	$	(b)
	(a)	Natural gas sold at fair value.
	(b)	Amount less than $1 million.

LongTerm_Debt_Tables

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2013
Long-term Debt, Unclassified [Abstract]	'
Schedule of Required and Actual Debt Ratios	'
	The following table summarizes these ratios for the 12 months ended and as of September 30, 2013:
		Required Ratio	Actual Ratio
	Interest coverage ratio- restricted payment(a)	≥1.75	1.05
	Interest coverage ratio- additional indebtedness(b)	≥2.50	1.05
	Debt-to-capital ratio- additional indebtedness (b)	≤60%	51	%
	(a)	As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.
	(b)	Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2013
Derivative Instrument Detail [Abstract]	'
Open Gross Derivative Volumes By Commodity Type	'
	The following table presents open gross commodity contract volumes by commodity type as of September 30, 2013, and December 31, 2012:
		Quantity (in millions)
	Commodity	Accrual & NPNS						Other
		Contracts(a)						Derivatives(b)
		2013			2012			2013			2012
	Coal (in tons)	26			30			3			5
	Fuel oils (in gallons)(c)	(d)			(d)			26			40
	Natural gas (in mmbtu)(e)	(d)			(d)			1			42
	Power	(f)			(f)			—			—
	(a)	Accrual contracts include commodity contracts that do not qualify as derivatives. As of September 30, 2013, these contracts ran through December 2017 for coal.
	(b)	As of September 30, 2013, these contracts ran through December 2015, October 2016, and April 2015 for coal, fuel oils, and natural gas, respectively.
	(c)	Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.
	(d)	Not applicable.
	(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.
Derivative Instruments Carrying Value	'
	The following table presents the carrying value and balance sheet location of all derivative instruments as of September 30, 2013, and December 31, 2012:
		Balance Sheet Location		2013				2012
	Derivative assets not designated as hedging instruments
	Commodity contracts:
	Coal	Other current assets		$	1			$	—
		Other assets		—				1
	Fuel oils	Other current assets		1				2
		Other assets		—				1
	Natural gas	Assets held for sale		—				4
		Total assets		$	2			$	8
	Derivative liabilities not designated as hedging instruments
	Commodity contracts:
	Coal	MTM derivative liabilities		$	5			$	7
		Other deferred credits and liabilities		1				3
	Fuel oils	MTM derivative liabilities		—				1
		Other deferred credits and liabilities		—				1
	Natural gas	Liabilities held for sale		—				3
		Total liabilities		$	6			$	15
Offsetting Derivative Assets and Liabilities	'
	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 September 30, 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)		$	2		$	2		$	—		$	—
	Liabilities:
	Commodity contracts eligible to be offset(b)		$	6		$	2		$	—		$	4
	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 is included in the “Other current liabilities” and “Other deferred credits and liabilities” lines in the balance sheet. Cash collateral posted reduces gross liability balances and is included in the “Other current assets” and “Other assets” lines in the balance sheet.
	(b)	Includes amounts classified as held for sale.
Maximum Exposure If Counterparties Fail To Perform On Contracts	'
	The following table presents the maximum exposure, as of September 30, 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				Commodity				Financial				Oil and Gas			Total
		Producers				Marketing				Companies				Companies
						Companies
	2013(a)	$	—			$	1			$	—			$	1		$	2
	2012(a)	$	2			$	1			$	2			$	2		$	7
	(a)	Includes amounts classified as held for sale.
Potential Loss On Counterparty Exposures	'
	The following table presents the potential loss after consideration of the application of master trading and netting agreements as of September 30, 2013, and December 31, 2012:
		Coal				Commodity				Financial				Oil and Gas			Total
		Producers				Marketing				Companies				Companies
						Companies
	2013(a)	$	—			$	1			$	—			$	1		$	2
	2012(a)	$	1			$	—			$	1			$	—		$	2
	(a)	Includes amounts classified as held for sale.
Derivative Instruments With Credit Risk-Related Contingent Features	'
	The following table presents, as of September 30, 2013, and December 31, 2012, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements assuming (1) the credit risk-related contingent features underlying these agreements were triggered on September 30, 2013, or December 31, 2012, respectively, and (2) those counterparties with rights to do so requested collateral:
		Aggregate Fair Value of				Cash				Potential Aggregate Amount of
		Derivative Liabilities(a)				Collateral Posted				Additional Collateral Required(b)
	2013(c)	$	34			$	—			$	32
	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 netting effects of such agreements.
	(c)	Includes amounts classified as held for sale.
Other Derivatives	'
	The following table represents the net change in market value for derivatives not designated as hedging instruments for the three and nine months ended September 30, 2013, and 2012:
			Location of Gain (Loss)		Gain (Loss) Recognized
			Recognized in Income		in Income
					Three Months								Nine Months
					2013				2012				2013			2012
	Coal		Operating Expenses - Fuel		$	—			$	—			$	4		$	(8	)
	Fuel oils		Operating Expenses - Fuel		2				5				—			(5		)
	Natural gas(a)		Operating Expenses - Fuel		—				(1		)		(1		)	3
	Power		Operating Revenues		(1		)		—				—			—
			Total		$	1			$	4			$	3		$	(10	)
	(a)	Includes amounts classified as held for sale.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Inputs, Assets and Liabilities, Quantitative Information	'
	financial assets and liabilities classified as Level 3 in the fair value hierarchy as of September 30, 2013. 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 as of December 31, 2012:
		Fair Value									Weighted
		Assets			Liabilities			Valuation Technique	Unobservable Input	Range	Average
	Level 3 Derivative asset and liability - commodity contracts(a):
	Fuel oils	$	1		$	—		Discounted cash flow	Escalation rate(%)(b)	.21 - .68	0.59
									Counterparty credit risk(%)(c)(d)	.12 - 1	1
									Genco credit risk(%)(c)(d)	31-Mar	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.
Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis	'
	The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of September 30, 2013, and December 31, 2012:
				Quoted Prices in				Significant Other				Significant Other				Total
				Active Markets for				Observable				Unobservable
				Identical Assets				Inputs				Inputs
				or Liabilities				(Level 2)				(Level 3)
				(Level 1)
	2013
	Assets:
		Derivative assets - commodity contracts(a):
		Coal		$	1			$	—			$	—			$	1
		Fuel oils		1				—				—				1
		Total assets		$	2			$	—			$	—			$	2
	Liabilities:
		Derivative liabilities - commodity contracts(a):
		Coal		$	6			$	—			$	—			$	6
		Total liabilities		$	6			$	—			$	—			$	6
	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.
Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level 3 In The Fair Value Hierarchy	'
	The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three and nine months ended September 30, 2013, and 2012:
		Net derivative commodity contracts
		Three Months Ended								Nine Months Ended
			2013				2012				2013				2012
	Fuel oils:
	Beginning balance		$	—			$	1			$	1			$	1
	Realized and unrealized gains (losses):
	Included in earnings(a)		1				—				—				—
	Total realized and unrealized gains (losses)		1				—				—				—
	Purchases		—				(1		)		—				—
	Settlements		(1		)		—				(1		)		—
	Transfers out of Level 3		—				1				—				—
	Ending balance		$	—			$	1			$	—			$	1
	Change in unrealized gains (losses) related to assets/liabilities held at September 30		$	—			$	—			$	—			$	—
	Power:
	Beginning balance		$	1			$	—			$	—			$	—
	Realized and unrealized gains (losses):
	Included in earnings		—				—				—				—
	Total realized and unrealized gains (losses)		—				—				—				—
	Purchases		—				—				(19		)		—
	Sales		—				—				21				—
	Settlements		(1		)		—				(2		)		—
	Ending balance		$	—			$	—			$	—			$	—
	Change in unrealized gains (losses) related to assets/liabilities held at September 30		$	—			$	—			$	—			$	—
	(a)	Net gains and losses on fuel oils derivative commodity contracts are recorded in “Operating Expenses – Fuel.”
Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt And Preferred Stock	'
	The following table presents the carrying amounts and estimated fair values of our long-term debt at September 30, 2013, and December 31, 2012:
		September 30, 2013								December 31, 2012
		Carrying Amount				Fair Value				Carrying Amount				Fair Value
	Long-term debt	$	824			$	639			$	824			$	618

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Schedule Of Estimated Capital Costs To Comply With Existing And Known Emissions Related Regulations	'
		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.

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended	9 Months Ended				0 Months Ended			0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2013	Mar. 14, 2013	Sep. 30, 2013	Dec. 31, 2012	Oct. 11, 2013
				EEI [Member]	Meredosia and Hutsonville Energy Centers [Member]	Elgin, Gibson City and Grand Tower Energy Centers [Member]	Elgin, Gibson City and Grand Tower Energy Centers [Member]	Elgin, Gibson City and Grand Tower Energy Centers [Member]	Subsequent Event [Member]
									Elgin, Gibson City and Grand Tower Energy Centers [Member]
Accounting Policies [Line Items]	'	'	'	'	'	'	'	'	'
Noncontrolling interest, ownership percentage by parent	'	'	'	80.00%	'	'	'	'	'
Impairment charge on long-lived assets	$70	'	'	'	'	'	'	'	'
Payment received from affiliate for asset sale	'	100	'	'	'	100	'	'	'
Additional payment received from affiliate for asset sale	'	'	'	'	'	'	'	'	37.5
Unrecognized tax benefits	'	5	'	'	'	'	'	'	'
Reduction to unrecognized tax benefits due to IRS guidance	'	4	'	'	'	'	'	'	'
Estimated unrecognized tax benefits, decreases resulting from settlements with taxing authorities	'	5	'	'	'	'	'	'	'
Percentage of EEI not owned by parent	'	'	'	20.00%	'	'	'	'	'
Asset retirement obligations	59	68	'	'	27	'	'	'	'
Asset retirement obligations (held for sale)	'	'	'	'	'	'	10	10	'
Accumulated benefit obligation	'	'	'	32	'	'	'	'	'
Assets relating to the plans overfunded status	'	'	'	$15	'	'	'	'	'

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Equity Changes Attributable to Noncontrolling Interest) (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Noncontrolling Interest	'		'		'		'
Noncontrolling interest, beginning of period	$8		$3		$8		$7
Net loss attributable to noncontrolling interest	'		-2		'		-6
Other comprehensive income attributable to noncontrolling interest	'	[1]	9	[1]	'	[1]	9	[1]
Noncontrolling interest, end of period	8		10		8		10
Reclassification adjustments for derivative income taxes (benefit)	'		30		1		33
Noncontrolling Interest [Member] [Member]	'		'		'		'
Noncontrolling Interest	'		'		'		'
Reclassification adjustments for derivative income taxes (benefit)	$0		$6		$0		$6
[1]	Represents the noncontrolling interest of EEI’s pension and other postretirement benefit plan activity, net of income taxes of $-, $6, $-, and $6, respectively.

Summary_of_Significant_Account5

Summary of Significant Accounting Policies (Schedule of Asset Retirement Obligations) (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Reconciliation of beginning and ending carrying amount of AROs [Roll Forward]	'
Balance at December 31, 2012	$59
Liabilities settled	1	[1]
Accretion	3
Change in estimates	6	[2]
Balance at September 30, 2013	$68
[1]	Less than $1 million
[2]	We changed our estimate due to updated retirement dates for certain CCR storage facilities during the first quarter of 2013. See Note 8 - Commitments and Contingencies for additional information regarding this change in estimate.

Summary_of_Significant_Account6

Summary of Significant Accounting Policies (Components Of Net Periodic Benefit Cost) (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Pension Benefits [Member]	'		'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'		'
Service cost	$1	[1]	$1	[1]	$3	[1]	$3	[1]
Interest cost	2	[1]	3	[1]	7	[1]	8	[1]
Expected return on plan assets	-3	[1]	-3	[1]	-10	[1]	-9	[1]
Prior service cost (benefit)	'	[1]	'	[1]	'	[1]	'	[1]
Actuarial loss	2	[1]	1	[1]	6	[1]	3	[1]
Curtailment loss	'	[1]	2	[1]	'	[1]	2	[1]
Net periodic benefit cost	2	[1]	4	[1]	6	[1]	7	[1]
Postretirement Benefits [Member]	'		'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'		'
Service cost	0	[1]	1	[1]	1	[1]	3	[1]
Interest cost	1	[1]	1	[1]	3	[1]	4	[1]
Expected return on plan assets	-1	[1]	-1	[1]	-4	[1]	-4	[1]
Prior service cost (benefit)	-2	[1]	'	[1]	-6	[1]	'	[1]
Actuarial loss	1	[1]	1	[1]	3	[1]	3	[1]
Curtailment loss	'	[1]	'	[1]	'	[1]	'	[1]
Net periodic benefit cost	($1)	[1]	$2	[1]	($3)	[1]	$6	[1]
[1]	Includes amounts for our participation in Ameren’s single-employer plans and the cost of EEI’s plans.

Summary_of_Significant_Account7

Summary of Significant Accounting Policies (Summary of Allocated Net Period Benefit Costs) (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Allocated Net Period Pension Benefits [Member]	'		'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'		'
Allocated benefit costs	$1		$1	[1]	$2		$1
Allocated Net Period Postretirement Benefits [Member]	'		'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'		'
Allocated benefit costs	$1	[1]	$1	[1]	$1	[1]	$1	[1]
[1]	Less than $1 million.

Assets_Held_for_Sale_Narrative

Assets Held for Sale (Narrative) (Details) (USD $)

3 Months Ended

9 Months Ended

0 Months Ended

3 Months Ended

9 Months Ended

0 Months Ended

0 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Mar. 14, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Sep. 30, 2013

Sep. 30, 2012

Mar. 28, 2012

Mar. 14, 2013

Sep. 30, 2013

Sep. 30, 2013

Oct. 11, 2013

Oct. 11, 2013

Oct. 11, 2013

Electric Energy Inc Pension and Other Postretirement Plans [Member]

Ameren Illinois Company [Member]

Elgin, Gibson City and Grand Tower Energy Centers [Member]

Elgin, Gibson City and Grand Tower Energy Centers [Member]

Elgin, Gibson City and Grand Tower Energy Centers [Member]

Elgin, Gibson City and Grand Tower Energy Centers [Member]

Elgin, Gibson City and Grand Tower Energy Centers [Member]

Elgin, Gibson City and Grand Tower Energy Centers [Member]

Elgin, Gibson City and Grand Tower Energy Centers [Member]

Initial Payment Received [Member]

Meredosia and Hutsonville Energy Centers [Member]

Ameren Energy Marketing Company [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

appraiser

Elgin, Gibson City and Grand Tower Energy Centers [Member]

Additional Payment Received [Member]

Total Payment Received [Member]

Long Lived Assets Held-for-sale [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Assets held for sale and impairment adjustments (Note 2)

($5)

'

$197

'

'

'

'

'

$5

$5

$207

$197

'

'

'

'

'

'

'

'

Benefit obligations

'

'

'

'

'

32

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Assets relating to the plans overfunded status

'

'

'

'

'

15

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset retirement obligations

68

'

68

'

59

'

'

'

'

'

'

'

'

'

'

27

'

'

'

'

Tax payable to Ameren Illinois

'

'

'

'

'

'

43

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Loss Carryforwards

80

'

80

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Tax Credit Carryforward, Amount

1

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payment received from affiliate for asset sale

'

'

100

'

'

'

'

100

'

'

'

'

'

'

100

'

'

'

37.5

137.5

Long-term debt, gross

825

'

825

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Transaction agreement, cash to be retained at Closing

70

'

70

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Put Option Premium

'

'

'

'

'

'

'

'

'

'

'

'

'

2.5

'

'

'

'

'

'

Other Amortization of Deferred Charges

'

'

'

'

'

'

'

'

'

'

1.5

'

1

'

'

'

'

'

'

'

Number of appraisers

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

Assets Held-for-sale, Long Lived, Fair Value Disclosure

'

'

'

'

'

'

'

133

137.5

'

'

137.5

'

'

'

'

'

'

'

'

Tax benefit from impairment

'

'

'

'

'

'

'

'

'

'

'

77

'

'

'

'

'

'

'

'

After-tax net proceeds on the maximum escrow amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15

'

'

Gain Contingency, Unrecorded Amount

$4

'

$4

'

'

'

'

'

'

'

'

'

'

'

'

'

$5

'

'

'

Assets_Held_for_Sale_Schedule_

Assets Held for Sale (Schedule of Assets Held for Sale) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Long Lived Assets Held-for-sale [Line Items]	'	'
Total assets held for sale	$152	$364
Total liabilities held for sale	15	25
Elgin, Gibson City and Grand Tower Energy Centers [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Materials and supplies	5	12
Mark-to-market derivative assets	'	4
Property and plant, net	147	348
Total assets held for sale	152	364
Accounts and wages payable	3	9
Taxes accrued	2	3
Mark-to-market derivative liabilities	'	3
Asset retirement obligations	10	10
Total liabilities held for sale	$15	$25

Related_Party_Transactions_Sch

Related Party Transactions (Schedule of Related Party Transactions) (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012		Dec. 31, 2012
									employee
Related Party Transaction [Line Items]	'		'		'		'		'
Number of employees transferred	'		'		'		'		74
Operating Revenues	$220		$217		$562		$604		'
Genco and EEI Power Supply Agreements with Marketing Company [Member]	'		'		'		'		'
Related Party Transaction [Line Items]	'		'		'		'		'
Operating Revenues	219		217		557		603		'
Natural Gas Sales to Medina Valley [Member]	'		'		'		'		'
Related Party Transaction [Line Items]	'		'		'		'		'
Operating Revenues	'		'		'		1	[1]	'
Services provided to AER affiliates [Member]	'		'		'		'		'
Related Party Transaction [Line Items]	'		'		'		'		'
Operating Revenues	1		1	[2]	5		1	[2]	'
Money Pool Borrowings Advances [Member]	'		'		'		'		'
Related Party Transaction [Line Items]	'		'		'		'		'
Interest (Charges) Income	1	[2]	1	[2]	1	[2]	1	[2]	'
Fuel [Member] | Ameren Missouri and Genco Gas Transportation Agreement [Member]	'		'		'		'		'
Related Party Transaction [Line Items]	'		'		'		'		'
Operating Expenses	1	[2]	1	[2]	1		1		'
Purchased Power [Member] | EEI Power Supply Agreement with Marketing Company [Member]	'		'		'		'		'
Related Party Transaction [Line Items]	'		'		'		'		'
Operating Expenses	47		1	[2]	65		1	[2]	'
Other Operations and Maintenance Expenses [Member] | Ameren Services Support Services Agreement [Member]	'		'		'		'		'
Related Party Transaction [Line Items]	'		'		'		'		'
Operating Expenses	$2		$7		$8		$17		'
[1]	Natural gas sold at fair value.
[2]	Amount less than $1 million.

ShortTerm_Debt_and_Liquidity_N

Short-Term Debt and Liquidity (Narrative) (Details) (USD $)	9 Months Ended		0 Months Ended				0 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Mar. 14, 2013	Mar. 14, 2013	Sep. 30, 2013	Sep. 30, 2013	Oct. 11, 2013	Sep. 30, 2013	Sep. 30, 2013
			Elgin, Gibson City and Grand Tower Energy Centers [Member]	Initial Payment Received [Member]	Ameren and Ameren Missouri [Member]	Ameren and Ameren Illinois [Member]	Subsequent Event [Member]	Parent Company [Member]	Parent Company [Member]
							Additional Payment Received [Member]	Ameren and Ameren Missouri [Member]	Ameren and Ameren Illinois [Member]
Line of Credit Facility [Line Items]	'	'	'	'	'	'	'	'	'
Payment received from affiliate for asset sale	$100,000,000	'	$100,000,000	$100,000,000	'	'	$37,500,000	'	'
Ameren, Ameren Missouri, and Ameren Illinois borrowing capacity under credit agreement	'	'	'	'	$1,000,000,000	$1,100,000,000	'	$500,000,000	$300,000,000

LongTerm_Debt_Schedule_of_Requ

Long-Term Debt (Schedule of Required and Actual Debt Ratios) (Details)	9 Months Ended
	Sep. 30, 2013
Restricted Payments [Member]	'
Debt Instrument [Line Items]	'
Interest Coverage Ratio	1.05	[1]
Restricted Payments [Member] | Minimum [Member]	'
Debt Instrument [Line Items]	'
Interest Coverage Ratio	1.75	[1]
Additional Indebtedness [Member] | Minimum [Member]	'
Debt Instrument [Line Items]	'
Interest Coverage Ratio	2.5	[2]
Maximum Leverage Ratio [Member]	'
Debt Instrument [Line Items]	'
Debt-to-capital ratio	0.6	[2]
Actual Ratio [Member]	'
Debt Instrument [Line Items]	'
Interest Coverage Ratio	1.05	[2]
Debt-to-capital ratio	0.51	[2]
[1]	As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.
[2]	Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Derivative_Financial_Instrumen2

Derivative Financial Instruments (Open Gross Derivative Volumes By Commodity Type) (Details)	Sep. 30, 2013		Dec. 31, 2012
	T		T
Accrual and Normal Purchases and Normal Sales Contracts [Member] | Coal [Member]	'		'
Derivative [Line Items]	'		'
Quantity	26,000,000	[1]	30,000,000	[1]
Other Contract [Member] | Coal [Member]	'		'
Derivative [Line Items]	'		'
Quantity	3,000,000	[2]	5,000,000	[2]
Other Contract [Member] | Fuel Oils [Member]	'		'
Derivative [Line Items]	'		'
Quantity	26,000,000	[2],[3]	40,000,000	[2],[3]
Other Contract [Member] | Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Quantity	1,000,000	[2],[4]	42,000,000	[2],[4]
Other Contract [Member] | Power [Member]	'		'
Derivative [Line Items]	'		'
Quantity	'	[2]	'	[2],[5]
[1]	Accrual contracts include commodity contracts that do not qualify as derivatives. As of September 30, 2013, these contracts ran through December 2017 for coal.
[2]	As of September 30, 2013, these contracts ran through December 2015, October 2016, and April 2015 for coal, fuel oils, and natural gas, respectively.
[3]	Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.
[4]	Amounts include commodity contracts classified as held for sale.
[5]	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.

Derivative_Financial_Instrumen3

Derivative Financial Instruments (Derivative Instruments Carrying Value) (Details) (Not Designated As Hedging Instrument [Member], USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivative [Line Items]	'	'
Derivative assets	$2	$8
Derivative liabilities	6	15
Coal [Member] | Other Current Assets [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	1	'
Coal [Member] | Other assets [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	'	1
Coal [Member] | MTM derivative liabilities [Member]	'	'
Derivative [Line Items]	'	'
Derivative liabilities	5	7
Coal [Member] | Other deferred credits and liabilities [Member]	'	'
Derivative [Line Items]	'	'
Derivative liabilities	1	3
Fuel Oils [Member] | Other Current Assets [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	1	2
Fuel Oils [Member] | Other assets [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	'	1
Fuel Oils [Member] | MTM derivative liabilities [Member]	'	'
Derivative [Line Items]	'	'
Derivative liabilities	'	1
Fuel Oils [Member] | Other deferred credits and liabilities [Member]	'	'
Derivative [Line Items]	'	'
Derivative liabilities	'	1
Natural Gas [Member] | Current assets held for sale [Member]	'	'
Derivative [Line Items]	'	'
Derivative assets	'	4
Derivative liabilities	'	$3

Derivative_Financial_Instrumen4

Derivative Financial Instruments (Offsetting Derivative Assets and Liabilities) (Details) (Commodity Contracts [Member], USD $)	Sep. 30, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Commodity Contracts [Member]	'		'
Offsetting Assets and Liabilities [Line Items]	'		'
Gross Amounts Recognized in the Consolidated Balance Sheet - Assets	$2	[1],[2]	$8	[1],[2]
Gross Amounts Not Offset in the Consolidated Balance Sheet	2	[2]	5	[2]
Cash Collateral Received/Posted	'	[2],[3]	'	[2],[3]
Net Amount	'	[2]	3	[2]
Gross Amounts Recognized in the Consolidated Balance Sheet - Liabilities	6	[1],[2]	15	[1],[2]
Gross Amounts Not Offset in the Consolidated Balance Sheet	2	[2]	5	[2]
Cash Collateral Received/Posted	'	[2],[3]	'	[2],[3]
Net Amount	$4	[2]	$10	[2]
[1]	The derivative asset and liability balances are presented net of counterparty credit considerations. Balances include amounts classified as held for sale.
[2]	Includes amounts classified as held for sale.
[3]	Cash collateral received reduces gross asset balances and is included in the “Other current liabilities” and “Other deferred credits and liabilities” lines in the balance sheet. Cash collateral posted reduces gross liability balances and is included in the “Other current assets” and “Other assets” lines in the balance sheet.

Derivative_Financial_Instrumen5

Derivative Financial Instruments (Maximum Exposure If Counterparties Fail To Perform On Contracts) (Details) (USD $)	9 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Concentration Risk [Line Items]	'		'
Maximum exposure to counterparties related to derivative contracts	$2	[1]	$7	[1]
Coal Producers [Member]	'		'
Concentration Risk [Line Items]	'		'
Maximum exposure to counterparties related to derivative contracts	'	[1]	2	[1]
Commodity Marketing Companies [Member]	'		'
Concentration Risk [Line Items]	'		'
Maximum exposure to counterparties related to derivative contracts	1	[1]	1	[1]
Financial Companies [Member]	'		'
Concentration Risk [Line Items]	'		'
Maximum exposure to counterparties related to derivative contracts	'	[1]	2	[1]
Oil And Gas Companies [Member]	'		'
Concentration Risk [Line Items]	'		'
Maximum exposure to counterparties related to derivative contracts	$1	[1]	$2	[1]
[1]	Includes amounts classified as held for sale.

Derivative_Financial_Instrumen6

Derivative Financial Instruments (Potential Loss On Counterparty Exposures) (Details) (USD $)	Sep. 30, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Concentration Risk [Line Items]	'		'
Potential loss on counterparty exposures related to derivative contracts	$2	[1]	$2	[1]
Coal Producers [Member]	'		'
Concentration Risk [Line Items]	'		'
Potential loss on counterparty exposures related to derivative contracts	'	[1]	1	[1]
Commodity Marketing Companies [Member]	'		'
Concentration Risk [Line Items]	'		'
Potential loss on counterparty exposures related to derivative contracts	1	[1]	'	[1]
Financial Companies [Member]	'		'
Concentration Risk [Line Items]	'		'
Potential loss on counterparty exposures related to derivative contracts	'	[1]	1	[1]
Oil And Gas Companies [Member]	'		'
Concentration Risk [Line Items]	'		'
Potential loss on counterparty exposures related to derivative contracts	$1	[1]	'	[1]
[1]	Includes amounts classified as held for sale.

Derivative_Financial_Instrumen7

Derivative Financial Instruments (Derivative Instruments With Credit Risk-Related Contingent Features) (Details) (USD $)	Sep. 30, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Derivative Instrument Detail [Abstract]	'		'
Aggregate Fair Value of Derivative Liabilities	$34	[1]	$48	[1]
Cash Collateral Posted	'		'
Potential Aggregate Amount of Additional Collateral Required	$32	[2]	$31	[2]
[1]	Prior to consideration of master trading and netting agreements and including accrual and NPNS contract exposures.
[2]	As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the netting effects of such agreements.

Derivative_Financial_Instrumen8

Derivative Financial Instruments (Other Derivatives) (Details) (Not Designated As Hedging Instrument [Member], USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Derivative [Line Items]	'		'		'		'
Gain (Loss) Recognized in Income	$1		$4		$3		($10)
Coal [Member] | Operating Expenses - Fuel [Member]	'		'		'		'
Derivative [Line Items]	'		'		'		'
Gain (Loss) Recognized in Income	'		'		4		-8
Fuel Oils [Member] | Operating Expenses - Fuel [Member]	'		'		'		'
Derivative [Line Items]	'		'		'		'
Gain (Loss) Recognized in Income	2		5		'		-5
Natural Gas (Generation) [Member] | Operating Expenses - Fuel [Member]	'		'		'		'
Derivative [Line Items]	'		'		'		'
Gain (Loss) Recognized in Income	'	[1]	-1	[1]	-1	[1]	3	[1]
Power [Member] | Operating Revenues Electric [Member]	'		'		'		'
Derivative [Line Items]	'		'		'		'
Gain (Loss) Recognized in Income	($1)		'		'		'
[1]	Includes amounts classified as held for sale.

Derivative_Financial_Instrumen9

Derivative Financial Instruments (Narrative) (Details) (Interest Rate Swap [Member], USD $)	9 Months Ended		3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
			Interest Charges [Member]	Interest Charges [Member]	Interest Charges [Member]	Interest Charges [Member]
Derivative [Line Items]	'	'	'	'	'	'
Cumulative deferred pretax gains (losses)	($6)	($7)	'	'	'	'
Cash flow hedge gain (loss) reclassified to revenue, amortization period	'10 years	'	'	'	'	'
(Gain) Loss Reclassified from Accumulated OCI into Income	'	'	1	1	1	1
Loss amortized over the next 12 months	$1.40	'	'	'	'	'

Fair_Value_Measurements_Narrat

Fair Value Measurements (Narrative) (Details) (USD $)	9 Months Ended			3 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Sep. 30, 2012
				Fuel Oils [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Gain (loss) recognized related to valuation adjustments for counterparty default risk (less than $1 million)	$1	$1	'	'
Counterparty default risk liability valuation adjustment related to derivative contracts (less than $1 million)	1	'	1	'
Transfers out of Level 3 into Level 1	'	'	'	$1

Fair_Value_Measurements_Schedu

Fair Value Measurements (Schedule of Valuation Process and Unobservable Inputs) (Details) (Fuel Oils [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
Fair Value Inputs, Assets And Liabilities, Quantitative Information [Line Items]	'
Derivative assets	1	[1]
Derivative liabilities	'	[1]
Discounted Cash Flow [Member] | Minimum [Member]	'
Fair Value Inputs [Abstract]	'
Escalation rate	0.21%
Counterparty credit risk	0.12%	[2],[3]
Genco credit risk	3.00%	[2],[3]
Discounted Cash Flow [Member] | Maximum [Member]	'
Fair Value Inputs [Abstract]	'
Escalation rate	0.68%
Counterparty credit risk	1.00%	[2],[3]
Genco credit risk	31.00%	[2],[3]
Discounted Cash Flow [Member] | Weighted Average [Member]	'
Fair Value Inputs [Abstract]	'
Escalation rate	0.59%
Counterparty credit risk	1.00%	[2],[3]
Genco credit risk	24.00%	[2],[3]
Option Model [Member] | Minimum [Member]	'
Fair Value Inputs [Abstract]	'
Volatilities	19.00%
Option Model [Member] | Maximum [Member]	'
Fair Value Inputs [Abstract]	'
Volatilities	27.00%
Option Model [Member] | Weighted Average [Member]	'
Fair Value Inputs [Abstract]	'
Volatilities	23.00%
[1]	The derivative asset and liability balances are presented net of counterparty credit considerations.
[2]	Counterparty credit risk is only applied to counterparties with derivative asset balances. Our credit risk is only applied to counterparties with derivative liability balances.
[3]	Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.

Fair_Value_Measurements_Schedu1

Fair Value Measurements (Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis) (Details) (USD $)	Sep. 30, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Fuel Oils [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	'		$1	[1]
Derivative liabilities	'		'	[1]
Commodity Contracts [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	2	[2],[3]	8	[2],[3]
Derivative liabilities	6	[2],[3]	15	[2],[3]
Commodity Contracts [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	2	[2]	7	[2]
Derivative liabilities	6	[2]	15	[2]
Commodity Contracts [Member] | Significant Other Observable Inputs (Level 2) [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	'	[2]	'	[2]
Derivative liabilities	'	[2]	'	[2]
Commodity Contracts [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	'	[2]	1	[2]
Derivative liabilities	'	[2]	'	[2]
Commodity Contracts [Member] | Coal [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	1	[2]	1	[2]
Derivative liabilities	6	[2]	10	[2]
Commodity Contracts [Member] | Coal [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	1	[2]	1	[2]
Derivative liabilities	6	[2]	10	[2]
Commodity Contracts [Member] | Coal [Member] | Significant Other Observable Inputs (Level 2) [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	'	[2]	'	[2]
Derivative liabilities	'	[2]	'	[2]
Commodity Contracts [Member] | Coal [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	'	[2]	'	[2]
Derivative liabilities	'	[2]	'	[2]
Commodity Contracts [Member] | Fuel Oils [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	1	[2]	3	[2]
Derivative liabilities	'		2	[2]
Commodity Contracts [Member] | Fuel Oils [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	1	[2]	2	[2]
Derivative liabilities	'		2	[2]
Commodity Contracts [Member] | Fuel Oils [Member] | Significant Other Observable Inputs (Level 2) [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	'	[2]	'	[2]
Derivative liabilities	'		'	[2]
Commodity Contracts [Member] | Fuel Oils [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	'	[2]	1	[2]
Derivative liabilities	'		'	[2]
Commodity Contracts [Member] | Natural Gas [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	'		4	[2]
Derivative liabilities	'		3	[2]
Commodity Contracts [Member] | Natural Gas [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	'		4	[2]
Derivative liabilities	'		3	[2]
Commodity Contracts [Member] | Natural Gas [Member] | Significant Other Observable Inputs (Level 2) [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	'		'	[2]
Derivative liabilities	'		'	[2]
Commodity Contracts [Member] | Natural Gas [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'		'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'
Derivative assets	'		'	[2]
Derivative liabilities	'		'	[2]
[1]	The derivative asset and liability balances are presented net of counterparty credit considerations.
[2]	The derivative asset and liability balances are presented net of counterparty credit considerations. Balances include amounts classified as held for sale.
[3]	Includes amounts classified as held for sale.

Fair_Value_Measurements_Schedu2

Fair Value Measurements (Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level 3 In The Fair Value Hierarchy) (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Fuel Oils [Member]	'		'		'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]	'		'		'		'
Beginning balance	$0		$1		$1		$1
Included in earnings	1	[1]	'	[1]	'	[1]	'	[1]
Total realized and unrealized gains (losses)	1		'		'		0
Purchases	'		-1		'		'
Settlements	-1		'		-1		'
Transfers out of Level 3	'		1		'		'
Ending balance	0		1		0		1
Change in unrealized gains (losses) related to assets/liabilities still held	'		'		'		'
Power [Member]	'		'		'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]	'		'		'		'
Beginning balance	1		0		0		0
Included in earnings	'	[1]	'	[1]	'	[1]	'	[1]
Total realized and unrealized gains (losses)	'		0		'		0
Purchases	'		'		-19		'
Sales	'		'		21		'
Settlements	-1		'		-2		'
Ending balance	0		0		0		0
Change in unrealized gains (losses) related to assets/liabilities still held	'		'		'		'
[1]	Net gains and losses on fuel oils derivative commodity contracts are recorded in “Operating Expenses – Fuel.”

Fair_Value_Measurements_Schedu3

Fair Value Measurements (Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt And Preferred Stock) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Carrying Amount [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term debt	$824	$824
Fair Value [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term debt	$639	$618

Commitments_and_Contingencies_1

Commitments and Contingencies (Environmental and Other Matters) (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
	state
Loss Contingencies [Line Items]	'
Other obligations related to procurement	$383,000,000
Number of states participating in the cap-and-trade program	28
Percent of top performing facilities	12.00%
New Source Review and Clean Air Litigation [Member] | Other Current Liabilities [Member]	'
Loss Contingencies [Line Items]	'
Accrual for environmental loss contingencies, current	3,000,000
Minimum [Member]	'
Loss Contingencies [Line Items]	'
Estimated capital costs to comply with existing and known federal and state air emissions regulations	350,000,000	[1]
Maximum [Member]	'
Loss Contingencies [Line Items]	'
Estimated capital costs to comply with existing and known federal and state air emissions regulations	425,000,000	[1]
Estimated Capital Costs 2013 [Member] | Minimum [Member]	'
Loss Contingencies [Line Items]	'
Estimated capital costs to comply with existing and known federal and state air emissions regulations	30,000,000
Estimated Capital Costs 2013 [Member] | Maximum [Member]	'
Loss Contingencies [Line Items]	'
Estimated capital costs to comply with existing and known federal and state air emissions regulations	30,000,000
Estimated Capital Costs 2013 to 2017 [Member] | Newton Energy Center Scrubbers [Member]	'
Loss Contingencies [Line Items]	'
Estimated capital costs to comply with existing and known federal and state air emissions regulations	20,000,000
Estimated Capital Costs 2014 to 2017 [Member] | Minimum [Member]	'
Loss Contingencies [Line Items]	'
Estimated capital costs to comply with existing and known federal and state air emissions regulations	100,000,000
Estimated Capital Costs 2014 to 2017 [Member] | Maximum [Member]	'
Loss Contingencies [Line Items]	'
Estimated capital costs to comply with existing and known federal and state air emissions regulations	125,000,000
Estimated Capital Costs 2018 to 2022 [Member] | Minimum [Member]	'
Loss Contingencies [Line Items]	'
Estimated capital costs to comply with existing and known federal and state air emissions regulations	220,000,000
Estimated Capital Costs 2018 to 2022 [Member] | Maximum [Member]	'
Loss Contingencies [Line Items]	'
Estimated capital costs to comply with existing and known federal and state air emissions regulations	$270,000,000
[1]	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.

Commitments_and_Contingencies_2

Commitments and Contingencies (Asbestos-Related Litigation And Tax Exemptions And Credits) (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Asbestos-Related [Member]	'
Loss Contingencies [Line Items]	'
Number of pending asbestos lawsuits as of the balance sheet date	6
Ameren Illinois Company [Member] | Claimed Manufacturing Exemptions And Credits [Member]	'
Loss Contingencies [Line Items]	'
Gain (Loss) Related to Litigation Settlement	$5