Illinois Power Generating 10-K 28 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 21, 2014	Jun. 30, 2013
Entity Information [Line Items]	'	'	'
Entity Registrant Name	'ILLINOIS POWER GENERATING COMPANY	'	'
Entity Central Index Key	'0001135361	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Non-accelerated Filer	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Amendment Flag	'false	'	'
Entity Common Stock, Shares Outstanding	'	2,000	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'Yes	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Public Float	'	'	$0

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Current Assets	'	'
Cash and cash equivalents	$190	$25
Advances to money pool	0	27
Accounts receivable – affiliates	59	70
Miscellaneous accounts receivable	18	20
Materials and supplies	78	85
Other current assets	18	28
Assets held for sale	0	364
Total Current Assets	363	619
Property, plant and equipment, net	1,873	1,887
Other assets	28	26
Total Assets	2,264	2,532
Current Liabilities	'	'
Accounts and wages payable	45	54
Accounts payable – affiliates	0	12
Current portion of tax payable	0	6
Taxes accrued	12	14
Interest accrued	10	12
Current accumulated deferred income taxes, net	19	0
Other current liabilities	8	17
Liabilities held for sale	0	25
Total Current Liabilities	94	140
Long-term debt	824	824
Deferred Credits and Other Liabilities	'	'
Accumulated deferred income taxes, net	520	334
Tax payable	0	39
Asset retirement obligations	43	59
Pension and other postretirement benefits	18	92
Other deferred credits and liabilities	2	16
Total Deferred Credits and Other Liabilities	583	540
Commitments and Contingencies (Note 10)	'	'
Stockholder’s Equity	'	'
Common stock, no par value, 10,000 shares authorized; 2,000 shares outstanding	0	0
Other paid-in capital	551	656
Retained earnings	216	404
Accumulated other comprehensive loss	-11	-40
Total Illinois Power Generating Company Stockholder’s Equity	756	1,020
Noncontrolling Interest	7	8
Total Equity	763	1,028
Total Liabilities and Equity	$2,264	$2,532

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]	'	'
Common Stock, No Par Value	$0	$0
Common stock, shares authorized	10,000	10,000
Common stock, shares outstanding	2,000	2,000

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Revenues:	'	'	'
Operating Revenues (Note 1)	$804	$808	$1,066
Operating Expenses:	'	'	'
Fuel	459	482	541
Purchased power	141	1	55
Other operations and maintenance	123	166	179
Impairment and other charges	199	70	35
Depreciation and amortization	80	85	96
Taxes other than income taxes	15	21	21
Total operating expenses	1,017	825	927
Operating Income (Loss)	-213	-17	139
Other Income and Expenses:	'	'	'
Miscellaneous income	1	1	1
Miscellaneous expense	0	1	0
Total other income	1	0	1
Interest Charges	42	52	63
Income (Loss) Before Income Tax	-254	-69	77
Income Tax Expense (Benefit) (Note 7)	-65	-29	32
Net Income (Loss)	-189	-40	45
Less: Net Income (Loss) Attributable to Noncontrolling Interest	-1	-7	1
Net Income (Loss) Attributable to Illinois Power Generating Company	($188)	($33)	$44

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (Loss) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Statement of Other Comprehensive Income [Abstract]	'		'		'
Net Income (Loss)	($189)		($40)		$45
Other Comprehensive Income (Loss), Net of Tax:	'		'		'
Reclassification adjustments for derivative losses included in net income (loss), net of income taxes	1	[1]	1	[1]	1
Pension and other postretirement benefit plan activity, net of income tax expense (benefit) of $21, $28 and $(24), respectively	28		39		-34
Total other comprehensive income (loss), net of taxes	29		40		-33
Comprehensive Income (Loss)	-160		0		12
Less: Total Comprehensive Income (Loss) Attributable to Noncontrolling Interest	-1		1		-4
Total Comprehensive Income (Loss) Attributable to Illinois Power Generating Company	($159)		($1)		$16
[1]	Amount related to the reclassification of mark-to-market loss on cash flow hedging activities, net and was recorded in Interest Charges in our consolidated statements of operations.

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Other Comprehensive Income [Abstract]	'	'	'
Pension and Other Postretirement Benefit Plans, Tax	$21	$28	($24)

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'	'
Net income (loss)	($189)	($40)	$45
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'	'
Impairment and other charges	199	70	35
Curtailment gain on pension and postretirement benefits	-26	0	0
Net mark-to-market (gain) loss on derivatives	-7	18	2
Depreciation and amortization	80	85	98
Deferred income taxes and investment tax credits, net	-1	-9	64
Other	0	9	-8
Changes in assets and liabilities:	'	'	'
Receivables	6	9	19
Materials and supplies	15	27	5
Accounts and wages payable	-14	6	-15
Other	-12	-36	-30
Net cash provided by operating activities	51	139	215
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Capital expenditures	-55	-175	-141
Proceeds from sales of properties	138	6	49
Money pool advances, net	27	47	-49
Net cash provided by (used in) investing activities	110	-122	-141
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'	'
Credit facility repayments, net	0	0	-100
Capital contribution from parent	4	0	28
Net cash provided by (used in) financing activities	4	0	-72
Net change in cash and cash equivalents	165	17	2
Cash and cash equivalents at beginning of year	25	8	6
Cash and cash equivalents at end of year	190	25	8
Cash Paid (Refunded) During the Year:	'	'	'
Interest (net of $18, $13 and $3 capitalized, respectively)	41	49	60
Income taxes, net	-65	-15	-25
Noncash investing and financing activities:	'	'	'
Capital contributions from parent	$72	$0	$0

Consolidated_Statements_of_Cas1

Consolidated Statements of Cash Flows (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Cash Flows [Abstract]	'	'	'
Capitalized interest	$18	$13	$3

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Stockholders' Equity (USD $)	Total	Total Illinois Power Generating Company Stockholders' Equity [Member]	Common Stock [Member]	Other Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]
In Millions, except Share data, unless otherwise specified
Beginning of year at Dec. 31, 2010	'	'	'	$649	$393	($44)	$11
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'
Common Stock	'	'	0	'	'	'	'
Capital contribution from parent	28	'	'	4	'	'	'
Adjustments to tax NOLs and other attributes from acquisition	'	'	'	0	'	'	'
Other	'	'	'	0	'	'	'
Net income (loss) attributable to Illinois Power Generating Company	44	'	'	'	44	'	'
Other comprehensive income (loss)	-33	'	'	'	'	-28	'
Net income (loss) attributable to noncontrolling interest holder	1	'	'	'	'	'	1
Other comprehensive income (loss) attributable to noncontrolling interest holder	'	'	'	'	'	'	-5
End of year at Dec. 31, 2011	'	1,025	'	653	437	-72	7
Total Equity at Dec. 31, 2011	'	1,018	'	'	'	'	'
Common stock, shares outstanding	2,000	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'
Common Stock	'	'	0	'	'	'	'
Capital contribution from parent	0	'	'	0	'	'	'
Adjustments to tax NOLs and other attributes from acquisition	'	'	'	0	'	'	'
Other	'	'	'	3	'	'	'
Net income (loss) attributable to Illinois Power Generating Company	-33	'	'	'	-33	'	'
Other comprehensive income (loss)	40	'	'	'	'	32	'
Net income (loss) attributable to noncontrolling interest holder	-7	'	'	'	'	'	-7
Other comprehensive income (loss) attributable to noncontrolling interest holder	'	'	'	'	'	'	8
End of year at Dec. 31, 2012	1,028	1,028	'	656	404	-40	8
Total Equity at Dec. 31, 2012	1,020	1,020	'	'	'	'	'
Beginning of year at Sep. 30, 2012	'	'	'	'	'	'	'
Common stock, shares outstanding	2,000	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'
Common Stock	'	'	0	'	'	'	'
Net income (loss) attributable to Illinois Power Generating Company	-41	'	'	'	'	'	'
End of year at Dec. 31, 2012	1,028	1,028	'	656	404	-40	8
Total Equity at Dec. 31, 2012	1,020	1,020	'	'	'	'	'
Common stock, shares outstanding	2,000	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'
Common Stock	'	'	0	'	'	'	'
Capital contribution from parent	4	'	'	76	'	'	'
Adjustments to tax NOLs and other attributes from acquisition	-178	'	'	-178	'	'	'
Other	'	'	'	-3	'	'	'
Net income (loss) attributable to Illinois Power Generating Company	-188	'	'	'	-188	'	'
Other comprehensive income (loss)	29	'	'	'	'	29	'
Net income (loss) attributable to noncontrolling interest holder	-1	'	'	'	'	'	-1
Other comprehensive income (loss) attributable to noncontrolling interest holder	'	'	'	'	'	'	0
End of year at Dec. 31, 2013	763	763	'	551	216	-11	7
Total Equity at Dec. 31, 2013	756	756	'	'	'	'	'
Beginning of year at Sep. 30, 2013	'	'	'	'	'	'	'
Common stock, shares outstanding	2,000	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'
Common Stock	'	'	0	'	'	'	'
Adjustments to tax NOLs and other attributes from acquisition	-178	'	'	'	'	'	'
Net income (loss) attributable to Illinois Power Generating Company	-32	'	'	'	'	'	'
End of year at Dec. 31, 2013	763	763	'	'	'	'	'
Total Equity at Dec. 31, 2013	$756	$756	'	'	'	'	'

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	General
	We are an electric generation subsidiary of IPH, which is an indirect wholly-owned subsidiary of Dynegy. We are headquartered in Houston, Texas and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois.
	We have an 80% ownership interest in EEI. EEI operates merchant electric generation facilities and FERC-regulated transmission facilities in Illinois and Kentucky. We also consolidate our wholly-owned subsidiary, Coffeen and Western Railroad Company, for financial reporting purposes. All significant intercompany transactions have been eliminated.
	Our accounting policies conform to GAAP. Financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. Our financial condition at December 31, 2013 and 2012 and our results of operations for each of the years ended December 31, 2013, 2012 and 2011 are presented on a comparable basis. 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.
	On December 2, 2013, we were acquired by IPH, an indirect wholly-owned subsidiary of Dynegy. In connection with the AER Acquisition, Ameren retained certain historical obligations of AER and its subsidiaries, including certain historical environmental and tax liabilities. Ameren forgave certain liabilities related to pre-acquisition activities, and retained existing AROs, which were recorded as a capital contribution totaling $72 million. We did not apply “push-down accounting” as a result of the AER Acquisition which would require the adjustment of assets and liabilities to fair value recognized by Dynegy to be shown in our consolidated financial statements. Our approximately $825 million in aggregate principal amount of long-term notes payable remain outstanding as an obligation of Genco. IPH and its direct and indirect subsidiaries, including Genco, are organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and its other subsidiaries, for the purpose of minimizing risk of claims against Dynegy for IPH’s and our obligations. We have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. We maintain separate books, records and bank accounts and separately appoint officers.  Furthermore, we pay liabilities from our own funds, conduct business in our own name and have restrictions on pledging our assets for the benefit of certain other persons.  See below and Note 2—Related Party Transactions, Note 4—Short-Term Debt and Liquidity, Note 6—Retirement Benefits, Note 7—Income Taxes and Note 10—Commitments and Contingencies for the impacts on these consolidated financial statements as a result of the AER Acquisition.
	Cash and Cash Equivalents
	Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.
	Materials and Supplies
	Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when installed, as appropriate. The following table presents a breakdown of materials and supplies at December 31, 2013 and 2012:
			Year Ended December 31,
	(amounts in millions)		2013			2012
	Fuel (a)		$	45		$	48
	Other materials and supplies		33			37
	Total		$	78		$	85
	__________________________________________
	(a)	Consists of coal for 2013 and coal and natural gas for 2012.
	Property, Plant and Equipment
	The cost of additions to and betterments of units of property, plant and equipment are capitalized. The cost includes labor, material, applicable taxes, and overhead. Interest incurred during construction is capitalized as a cost of assets. Expenditures for major installations, replacements and improvements or betterments are capitalized and depreciated over the expected life cycle. Expenditures for maintenance, repairs and minor renewals to maintain the operating condition of our assets are expensed. When units of depreciable property are retired, the original costs, less salvage values, are charged to accumulated depreciation. Asset removal costs incurred that do not constitute legal obligations are generally expensed as incurred. Please read Asset Retirement Obligations below and Note 3—Property, Plant and Equipment, for further discussion.
	Depreciation
	Depreciation is provided using the straight-line method over the estimated service lives of the assets, ranging from 1 to 36 years. Our provision for depreciation in 2013, 2012 and 2011 has an average depreciable cost of approximately 3%.
	The estimated economic service lives of our asset groups are as follows:
	Asset Group		Range of
			Years
	Power generation facilities		1 to 30
	Environmental upgrades		10 to 30
	Buildings and improvements		7 to 36
	Office and other equipment		2 to 15
	Intangible Assets
	We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.
	At December 31, 2013 and 2012, intangible assets consisted of emission allowances. The book value of emission allowances was less than $1 million at the end of both years. Emission allowances are charged to fuel expense as they are used in operations. Amortization expense based on usage of emission allowances, net of gains from sales, excluding intangible asset impairment charges discussed below, were less than $1 million, $1 million and $2 million during the years ended December 31, 2013, 2012 and 2011, respectively.
	Please read Note 11—Impairment and Other Charges for further discussion.
	Impairment of Long-lived Assets
	We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which we determine an asset meets held for sale criteria, we record an impairment charge to the extent the carrying value exceeds its fair value less cost to sell. Please read Note 11—Impairment and Other Charges for further discussion.
	Environmental Costs
	Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.
	Unamortized Debt Discount, Premium and Expense
	Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues.
	Operating Revenue
	Revenue is earned from the facilities based on generation for the sale of energy and the sale of capacity. Operating revenue for electric service is recorded based on net generation in accordance with our PSA with IPM. Revenue is recognized when the product or service is delivered to a customer, unless they meet the definition of a derivative.
	Income Taxes
	Upon the AER Acquisition, we were acquired in a transaction that resulted in an “ownership change,” as defined under IRC Section 382. Prior to the AER Acquisition, we were included in the consolidated federal and state income tax returns of Ameren Corporation. Genco and Ameren Corporation were parties to a tax sharing agreement that provided that the amount of tax recognized is similar to that which would have been owed had we been separately subject to tax.
	Upon the closing of the AER Acquisition, we are included in the consolidated federal and state returns of Dynegy. Genco and Dynegy have entered into a new tax sharing agreement. Under the terms of the new tax sharing agreement, we recognize taxes based on a separate company income tax return basis, as defined in the agreement. Under IRC Section 382, we are subject to a limitation in the amount of NOLs that could be used in any one year following this ownership change. Further, we are subject to a worthless stock loss deduction equal to Ameren’s tax basis in our stock prior to the AER Acquisition. Accordingly, we determined that our pre-acquisition NOLs are unlikely to be used against future taxable income and the estimated benefits therefrom have been written down to zero. We have also recorded the effects of a reduction of other tax attributes, totaling $433 million. These adjustments to our NOLs and tax attributes resulted in a charge to paid-in capital at the Acquisition Date of $178 million and a reduction to our income tax benefit for 2013 in the amount of $39 million. Please read Note 7—Income Taxes for further discussion.
	We use an asset and liability approach for our financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.
	Noncontrolling Interest
	Noncontrolling interest is comprised of the 20% of EEI we do not own. This noncontrolling interest is classified as a component of equity separate from our equity in the consolidated balance sheet.
	Accounting Changes and Other Matters
	The following is a summary of recently adopted authoritative accounting guidance as well as guidance issued but not yet adopted that could impact us.
	Accounting Standards Adopted
	Disclosures about Fair Value Measurements. In May 2011, FASB issued additional authoritative guidance regarding fair value measurements. The guidance amended the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments did not affect our results of operations, financial position, or liquidity, as this guidance only requires additional disclosures. We adopted this guidance for the first quarter 2012. Please read Note 9—Fair Value Measurements for further discussion.
	Presentation of Comprehensive Income. In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in separate but consecutive statements. This guidance was effective for us beginning in the first quarter 2012 with retroactive application required. The implementation of the amended guidance did not affect results of operations, financial position, or liquidity. In February 2013, the FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. The amendments did not affect our results of operations, financial position, or liquidity, as this guidance only requires additional disclosures and substantially all the information that this amended guidance requires is already disclosed elsewhere in the financial statements. This guidance was effective for us beginning in the first quarter 2013 on a prospective basis.
	Disclosures about Offsetting Assets and Liabilities. In December 2011, FASB issued additional authoritative guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The amendments did not affect our results of operations, financial positions or liquidity, as this guidance only requires additional disclosures. This guidance was effective for us beginning in the first quarter 2013 with retrospective application required.
	Accounting Standards Not Yet Adopted
	Presentation of Unrecognized Tax Benefits. In July 2013, the FASB issued ASU 2013-11-Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.  The provisions of the rule require an unrecognized tax benefit to be presented as a reduction to a deferred tax asset in the financial statements for an NOL carryforward, a similar tax loss, or a tax credit carryforward except in circumstances when the carryforward or tax loss is not available at the reporting date under the tax laws of the applicable jurisdiction to settle any additional income taxes or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes.  When those circumstances exist, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets.  The new financial statement presentation provisions relating to this update are prospective and effective for interim and annual periods beginning after December 15, 2013, with early adoption permitted.  We are currently assessing the future impact of this update, but we do not anticipate a material impact on our financial condition, results of operations or cash flows.
	Asset Retirement Obligations
	Authoritative accounting guidance requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments to AROs based on changes in the estimated fair values of the obligations. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing, or amount of cash flows associated with AROs affect our estimates of fair value. We have recorded AROs for retirement costs associated with asbestos removal, river structures and CCR storage facilities.
	The following table provides a reconciliation of the beginning and ending carrying amounts of AROs for the years ended December 31, 2012 and 2013:
	(amounts in millions)
	Balance at December 31, 2011		$	61
	Liabilities incurred		2
	Liabilities settled		(5		)
	Accretion in 2012		4
	Change in estimates		(3		)
Balance at December 31, 2012		59
Liabilities incurred		3
Liabilities settled (a)		(28		)
Accretion in 2013		4
Change in estimates		5
Balance at December 31, 2013		$	43
__________________________________________
(a)	Under the terms of the agreement entered into on March 14, 2013 to divest New AER to IPH, Ameren retained the existing AROs associated with the closure of the Meredosia and Hutsonville facilities, which were estimated at $28 million as of the date of divestiture, December 2, 2013.
Employee Separation and Other Charges
In each of the past three years, employee separation programs were initiated to reduce positions under the terms and benefits consistent with our former parent Ameren’s standard management separation program. We recorded pretax charges related to these programs of $3 million, $1 million and $4 million in 2013, 2012 and 2011, respectively. The 2013 and 2012 charges were recorded in “Other operations and maintenance” expense on the consolidated statements of operations. The 2011 charge related to the closure of the Meredosia and Hutsonville facilities and was recorded in “Impairment and other charges” on the consolidated statement of operations. Please read Note 11—Impairment and Other Charges for further discussion. In 2014, we expect to payout approximately $3 million of severance benefits to affected employees.
Asset Sales
We determined that the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired facilities (the “Gas-Fired Facilities”) first qualified for held for sale presentation beginning March 14, 2013. Therefore, beginning in the first quarter 2013, we segregated and reclassified the assets and liabilities associated with these Gas-Fired Facilities and presented them separately as held for sale at December 31, 2012. The operating results of the Gas-Fired Facilities did not qualify for discontinued operations presentation because we continue to sell power into the same markets with our remaining generation assets. As further discussed below, these facilities were sold prior to December 31, 2013 and there were no assets and liabilities held for sale on our consolidated balance sheet at December 31, 2013. The following table presents the components of assets and liabilities held for sale on our consolidated balance sheet at December 31, 2012:
(amounts in millions)		31-Dec-12
Assets held for sale
Materials and supplies		$	12
Mark-to-market derivative assets		4
Property, plant and equipment, net		348
Total assets held for sale		$	364
Liabilities held for sale
Accounts and wages payable		$	9
Taxes accrued		3
Mark-to-market derivative liabilities		3
Asset retirement obligations		10
Total liabilities held for sale		$	25
As a result of the assets and liabilities associated with the Gas-Fired Facilities meeting the held for sale criteria during 2013, we evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value less cost to sell. The estimated fair value was determined by reference to the amended put option agreement, the asset purchase agreement with Medina Valley, and the transaction agreement with IPH (as further described below and in Note 2—Related Party Transactions). We recorded a pretax charge to earnings of $199 million for 2013, to reflect the impairment of the Gas-Fired Facilities. The 2013 impairment recorded was primarily related to the Gas-Fired Facilities as the Elgin facility was previously impaired (pretax charge to earnings of $70 million) under held and used accounting guidance during the fourth quarter 2012. The 2013 impairment charge to earnings was recorded as an impairment of “Property, plant and equipment, net” within the components of assets held for sale shown above, and “Impairment and other charges” in our consolidated statement of operations for 2013. Please read Note 11—Impairment and Other Charges for further discussion. For 2013, we recorded an $82 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, based on the cash proceeds of $138 million, which is an input classified as Level 3 within the fair value hierarchy.
Effective with our conclusion in March 2013 that the Gas-Fired Facilities met the criteria for held for sale presentation, we suspended recording depreciation on these facilities.
On March 28, 2012, we entered into a put option agreement with AERG, which gave us the option to sell to AERG the Gas-Fired Facilities. 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 (the “Put Option”). On March 14, 2013, immediately prior to Ameren’s entry into the Transaction Agreement with IPH, we exercised our option under the put option agreement with Medina Valley and received an initial payment of $100 million with respect to the sale of the Gas-Fired Facilities to Medina Valley. On October 11, 2013, Ameren received FERC approval for the divestiture of New AER to IPH and our sale of the Gas-Fired Facilities to Medina Valley. Immediately after receipt of FERC approval, we completed the sale of these Gas-Fired Facilities to Medina Valley and received additional cash proceeds of approximately $38 million. Medina Valley entered into an agreement to sell the Gas-Fired Facilities with Rockland Capital (the “Rockland Agreement”). The sale of the Gas-Fired Facilities to an affiliate of Rockland Capital closed on January 31, 2014. Under the Put Option, Medina Valley is obligated to pay us after-tax proceeds realized on the sale of the Gas-Fired Facilities in excess of $138 million, net of any indemnifications per the Rockland Agreement, within two years of January 31, 2014.
In June 2011, we completed the sale of our remaining interest in the Columbia CT facility to the city of Columbia, Missouri.  We received cash proceeds of $45 million and recognized an $8 million pretax gain from the sale. In 2011, we sold additional property and assets for cash proceeds of $4 million, which resulted in pretax gains of $4 million.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 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. Below are the material related party agreements.
	Amended Put Option Agreement
	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 Gas-Fired Facilities for the greater of $100 million or the fair market value of the facilities. On March 14, 2013, this put option agreement was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley, an affiliate of Ameren. As discussed in Note 1—Summary of Significant Accounting Policies, this option was exercised on March 14, 2013, resulting in the asset purchase agreement with Medina Valley.
	Power Supply Agreements
	The following table presents the amount of physical power sales and purchases under our related party electric PSAs with IPM, including EEI’s PSA with IPM, in gigawatthours:
			Year Ended December 31,
			2013		2012	2011
	Genco sales to IPM		12,111		11,933	14,293
	EEI sales to IPM		6,856		6,421	7,633
	EEI purchases from IPM		29		22	886
	Genco has a PSA with IPM, whereby it agreed to sell and IPM agreed to purchase all of the capacity and energy available from its generation fleet. IPM entered into a similar PSA with IPRG. Under the PSAs, revenues allocated between Genco and IPRG are based on reimbursable expenses and generation of each entity. Each PSA will continue through December 31, 2022, and from year to year thereafter. Either party to the respective PSA may elect to terminate the PSA by providing the other party with no less than six months advance written notice. On February 26, 2014, Genco also entered into a collateral agreement with IPM pursuant to which Genco provides collateral to IPM to secure obligations of IPM applicable to Genco’s assets. There have been no amounts provided under this agreement to date.
	EEI has a PSA with IPM, whereby EEI agreed to sell and IPM agreed to purchase all of the capacity and energy available from EEI’s generation fleet. The price that IPM pays for capacity is set annually based upon prevailing market prices. IPM pays spot market prices for the associated energy. In addition, EEI will at times purchase energy from IPM to fulfill obligations to a nonaffiliated party. This PSA will continue through May 31, 2016.
	Support Services Agreements
	Prior to the AER Acquisition, Ameren Services provided support services to its affiliates, including us. The costs of support services, including wages, employee benefits, professional services, and other expenses, were based on, or were an allocation of, actual costs incurred. In addition, we provided affiliates, primarily Ameren Services, with access to our facilities for administrative purposes. The cost of the rent and facility services were based on, or were an allocation of, actual costs incurred.
	Upon the AER Acquisition, Dynegy and certain of its subsidiaries (collectively, the “Providers”) began providing certain services (the “Services”) to IPH, and certain of its consolidated subsidiaries (collectively, the “Recipients”), which includes us and EEI.
	The Providers act as agents for the Recipients for the limited purpose of providing the Services set forth in the service agreements. Prior to the beginning of each fiscal year in which Services are to be provided pursuant to the Service Agreements, the Providers and the Recipients agree on a budget for the Services, outlining, among other items, the contemplated scope of the Services to be provided in the following fiscal year and the cost of providing the Services. The Recipients will pay the Providers an annual management fee as agreed in the budget. We believe this allocation methodology is a reasonable method of allocating the costs of the Services to us and provides an appropriate reflection of the costs we would have incurred if we were operated as an unaffiliated entity.
	Tax Sharing Agreement
	Upon the AER Acquisition, we are included in the consolidated tax returns of Dynegy. Under U.S. federal income tax law, Dynegy files consolidated income tax returns for itself and its subsidiaries. Dynegy is responsible for the federal tax liabilities of its subsidiaries which include the income and business activities of the ring-fenced entities and Dynegy’s other affiliates.  Prior to the AER Acquisition, we are included in the consolidated federal and state income tax returns of Ameren Corporation. Genco and Ameren Corporation were parties to a tax sharing agreement that provided that the amount of tax recognized was similar to that which would have been owed had we been separately subject to tax. Genco and Dynegy have entered into a new tax sharing agreement that also provides that we recognize taxes based on a separate company income tax return basis, as defined in the agreement. As of December 31, 2013, we owed approximately $1 million to Dynegy pursuant to the new tax sharing agreement.
	Gas Sales and Transportation Agreement
	Prior to the AER Acquisition, under a gas transportation agreement, we acquired gas transportation services from Ameren Missouri that were expected to expire in February 2016. In connection with the AER Acquisition, we no longer have this agreement.
	Employee Transfer
	Through the end of 2012, some Ameren Services employees were included within AER’s business services group, which provided 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. In connection with the AER Acquisition, these support services were no longer provided to AER subsidiaries.
	Intercompany Transfers
	In 2012, we transferred various assets from our Hutsonville and Meredosia facilities to AERG. Both of the facilities were retired in 2011. We received cash proceeds in the amount of $3 million. The transfer of the assets was accounted for as a transaction between entities under common control; therefore, we did not recognize a gain on the transfer, but recognized an increase to other paid in capital for the amount of the proceeds.
	Intercompany Sales
	In 2012, we completed the sale of land for cash proceeds of $2 million to ATXI (Ameren Transmission Company of Illinois, an Ameren Corporation subsidiary that is engaged in the construction and operation of electric transmission assets). We recognized a $2 million gain from the sale.
	Money Pool
	On December 2, 2013, our ability to borrow under Ameren’s non-state-regulated subsidiary money pool arrangement was terminated in connection with the AER Acquisition. Please read Note 4—Short-Term Debt and Liquidity for further discussion of affiliate borrowing arrangements.
	Summary of Related Party Transactions
	The following table presents the impact of related party transactions. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4—Short-Term Debt and Liquidity.
				Year Ended December 31,
	(amounts in millions)		Income Statement Line Item	2013		2012		2011
	Genco and EEI power supply agreements with IPM		Operating Revenues	$	709	$	804	$	1,006
	Natural gas sales to Medina Valley (a)		Operating Revenues	—		1		3
	Services provided to AER affiliates		Operating Revenues	6		—		—
	Total Operating Revenues			$	715	$	805	$	1,009
	Ameren Missouri gas transportation agreement		Fuel	$	1	$	1	$	1
	EEI power supply agreement with IPM		Purchased Power	$	66	$	1	$	36
	Support services agreement		Other Operations and Maintenance	$	13	$	21	$	19
	Money pool borrowings (advances)		Interest (Charges) Income	(b)		(b)		(b)
	__________________________________________
	(a)	Natural gas sold at fair value.
	(b)	Amount less than $1 million.

Property_and_Plant_Net

Property and Plant, Net	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
PROPERTY AND PLANT, NET	'
	PROPERTY, PLANT AND EQUIPMENT
	A summary of our property, plant and equipment is as follows:
	(amounts in millions)	31-Dec-13			31-Dec-12
	Property, plant and equipment	$	2,551		$	2,787
	Less: Accumulated depreciation and amortization	(1,027		)	(1,192		)
		1,524			1,595
	Construction work in progress	349			292
	Property, plant and equipment, net	$	1,873		$	1,887
	Please read Note 11—Impairment and Other Charges for further discussion regarding non-cash long-lived asset impairments. The accrued capital expenditures at December 31, 2013, 2012 and 2011 were $3 million, $3 million and $13 million, respectively, which represent non-cash investing activity excluded from the statements of cash flows.

ShortTerm_Debt_and_Liquidity

Short-Term Debt and Liquidity	12 Months Ended
	Dec. 31, 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. There was no borrowing activity under the 2010 Genco Credit Agreement, prior to its termination, for the year ended December 31, 2012. On December 2, 2013, our ability to borrow under Ameren’s non-state-regulated subsidiary money pool arrangement was terminated in connection with the AER Acquisition. On March 14, 2013, we amended and exercised our option to sell our three natural Gas-Fired Facilities to Medina Valley and received an initial payment of $100 million. On October 11, 2013, we completed the sale of our Gas-Fired Facilities to Medina Valley and received an additional payment of $38 million.  With the additional liquidity received through such sales, our financing sources are estimated to be adequate to support our operations in 2014. Please read Note 1—Summary of Significant Accounting Policies for further discussion regarding the asset sales.
	Money Pool
	Ameren, Genco’s former parent, established a money pool to coordinate and to provide short-term cash and working capital to its subsidiaries. Our ability to access funding from the Ameren and Ameren Missouri’s $1 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 was terminated in connection with the AER Acquisition. Prior to such termination, when receiving a loan under the money pool agreement, we were required to repay the principal amount of such loan, together with accrued interest. The rate of interest depended on the composition of internal and external funds in the money pool. The average interest rate for borrowing under the money pool prior to the termination of our access to it for the year ended December 31, 2012 was 0.61%, and there were no borrowings for the year ended December 31, 2013. During the year ended December 31, 2013, Genco received less than $1 million of interest income from money pool advances. Please read Note 2—Related Party Transactions for further discussion of the amount of interest income and expense from the money pool arrangements prior to the termination of our access to it, for the years ended December 31, 2013, 2012 and 2011.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Long-term Debt, Unclassified [Abstract]	'
LONG-TERM DEBT	'
	LONG-TERM DEBT
	The following table presents our long-term debt outstanding:
	(amounts in millions)		31-Dec-13			31-Dec-12
	Unsecured notes:
	Senior notes Series F 7.95% due 2032		$	275		$	275
	Senior notes Series H 7.00% due 2018		300			300
	Senior notes Series I 6.30% due 2020		250			250
	Total long-term debt, gross		825			825
	Less: Unamortized discount		(1		)	(1		)
	Less: Maturities due within one year		—			—
	Long-term debt, net		$	824		$	824
	Aggregate maturities of the principal amounts of all long-term indebtedness, excluding unamortized discounts, as of December 31, 2013 are as follows: 2014—zero, 2015—zero, 2016—zero, 2017—zero, 2018—$300 million and thereafter—$525 million.
	Indenture Provisions and Other Covenants
	We are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive and (3) there is no self-dealing on the part of corporate officials.
	At December 31, 2013, we were in compliance with the provisions and covenants contained within our indenture. 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 required ratios:
			Required Ratio
	Restricted payment interest coverage ratio (a)		≥1.75
	Additional indebtedness interest coverage ratio (b)		≥2.50
	Additional indebtedness debt-to-capital ratio (b)		≤60%
	_______________________________________
	(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.
	(b)	Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. 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.
	Based on December 31, 2013 results, our interest coverage ratios are less than the minimum ratios required to pay dividends and borrow additional funds from external, third-party sources. Based on our projections, we expect that our interest coverage ratios will be less than the minimum ratios required to pay dividends and incur additional third-party indebtedness until at least 2016.
	In order for us to issue securities in the future, we will have to comply with all applicable requirements in effect at the time of any such issuances.
	Our indenture provides that dividends cannot be paid unless the actual interest coverage ratio for our most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on projections of operating results and cash flows in 2014 and 2015 as of December 31, 2013, we did not believe that we would achieve the minimum interest coverage ratio necessary to pay dividends on our common stock for each of the subsequent four six-month periods ending June 30, 2014, December 31, 2014, June 30, 2015, or December 31, 2015. As a result, we were restricted from paying dividends as of December 31, 2013, and we expect to be unable to pay dividends until at least 2016. No dividends were paid to our then-parent AER, prior to the AER Acquisition, in 2013, 2012, or 2011, nor to our parent subsequent to the AER Acquisition, IPR in 2013.
	Off-Balance Sheet Arrangements
	At December 31, 2013, we had no off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. We do not expect to engage in any significant off-balance sheet financing arrangements in the near future.

Retirement_Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2013
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]	'
RETIREMENT BENEFITS	'
	RETIREMENT BENEFITS
	We offer defined benefit pension and postretirement benefit plans covering our employees. Our employees and retirees, excluding EEI employees and retirees, participated in Ameren’s single-employer pension and other postretirement plans through December 1, 2013, prior to the AER Acquisition. Effective December 2, 2013, our employees and retirees, excluding EEI employees and retirees, participate in Dynegy’s single-employer pension and other postretirement plans. Separately, our EEI employees and retirees participate in EEI’s single-employer pension and other postretirement plans. We consolidate EEI, and therefore, EEI’s plans are reflected in our pension and postretirement balances and disclosures. We use a measurement date of December 31 for our pension and postretirement benefit plans.
	As a result of the AER Acquisition, Ameren retained the pension obligations associated with the current and former employees of Genco and the postretirement benefit obligations associated with the employees of Genco who were eligible to retire at December 2, 2013 with respect to such employees’ participation in Ameren’s single-employer pension and postretirement plans. Effective with the AER Acquisition, Dynegy assumed the postretirement benefit obligation for active union employees of New AER and its subsidiaries not eligible to retire based on the assumption of the collective bargaining agreements in place. Genco retained the pension and other postretirement benefit obligations associated with EEI’s current and former employees. As a result of the AER Acquisition, certain EEI employees were terminated which resulted in a curtailment gain of $26 million which was recorded in Other operations and maintenance in our consolidated statements of operations.
	For our disclosures below, unless otherwise noted, we have reflected the obligations, plan assets, and costs associated with EEI’s pension and postretirement plans. Also reflected is an allocation of our share of obligations, plan assets, and costs associated with our participation in Ameren’s single-employer pension and postretirement plans through December 1, 2013 and Dynegy’s single-employer pension and postretirement plans for the period from December 2, 2013 through December 31, 2013. The allocation of obligations, plan assets, and costs from our participation in Ameren’s and Dynegy’s single-employer pension plan was based on our employees’ share of total pensionable salaries. The allocation of obligations, plan assets, and costs from our participation in Ameren’s and Dynegy’s single-employer postretirement plans was based on the number of our employees.
	The following table presents the funded status of our pension and postretirement benefit plans as of December 31, 2013 and 2012. It also provides the amounts included in accumulated OCI at December 31, 2013 and 2012 that have not been recognized in net periodic benefit costs. These amounts include the funded status of EEI’s pension and postretirement plans as well as an allocation of our share of obligation and plan assets associated with our participation in Ameren’s and Dynegy’s single-employer pension and postretirement plans.
			2013								2012
	(amounts in millions)		Pension Benefits				Postretirement				Pension Benefits			Postretirement
							Benefits							Benefits
	Accumulated benefit obligation at end of year		$	89			N/A				$	251		N/A
	Change in benefit obligation:
	Net benefit obligation at beginning of year		$	251			$	93			$	239		$	150
	Transfer of liability from (to) Ameren Services / Medina Valley (a)		(7		)		(2		)		13			2
	Transfer of liability to Ameren (b)		(136		)		(33		)		—			—
	Allocation of liability from Dynegy (c)		—				4				—			—
	Service cost		5				2				5			3
	Interest cost		10				3				10			6
	Plan amendments (d)(e)		—				(4		)		(6		)	(75		)
	Participant contributions		—				1				—			1
	Actuarial (gain) loss		(11		)		(8		)		3			15
	Curtailments (f)		—				1				2			(1		)
	Benefits paid		(22		)		(7		)		(15		)	(8		)
	Administrative expenses paid		(1		)		—				—			—
	Net benefit obligation at end of year		89				50				251			93
	Change in plan assets:
	Fair value of plan assets at beginning of year		183				83				167			81
	Transfer of assets from Ameren Services / Medina Valley (a)		(6		)		(1		)		9			2
	Transfer of assets to Ameren (b)		(130		)		(21		)		—			—
	Actual return on plan assets		36				12				11			7
	Employer contributions		15				—				11			—
	Participant contributions		—				1				—			1
	Benefits paid		(22		)		(7		)		(15		)	(8		)
	Administrative expenses paid		(1		)		—				—			—
	Fair value of plan assets at end of year		75				67				183			83
	Funded status		$	14			$	(17	)		$	68		$	10
	Amounts recognized in the balance sheet consist of:
	Noncurrent asset (g)		$	—			$	(21	)		$	—		$	(14	)
	Current liability		—				—				—			—
	Noncurrent liability		14				4				68			24
	Net liability (asset) recognized		$	14			$	(17	)		$	68		$	10
	Amounts (pretax) recognized in accumulated OCI consist of:
	Net actuarial loss		$	17			$	44			$	73		$	59
	Prior service cost (credit)		(3		)		(43		)		(10		)	(62		)
	Total		$	14			$	1			$	63		$	(3	)
	_________________________________________
	(a)	In October 2013, 52 employees from Genco were transferred to Ameren Services and Medina Valley through an internal reorganization. On December 31, 2012, 74 employees from Ameren Services were transferred to Genco through an internal reorganization.
	(b)	Effective with the AER Acquisition, Ameren retained the portion of Genco’s pension obligations associated with the current and former employees of Genco and the portion of Genco’s postretirement benefit obligations associated with the employees of Genco who were eligible to retire at December 2, 2013 with respect to such employees’ participation in Ameren’s single-employer pension and postretirement plans.
	(c)	Amount represents the allocation of the obligation from our participation in Dynegy’s single-employer plans.
	(d)	Effective with the AER Acquisition, the EEI management postretirement plan was remeasured as a result of a reduction in employees participating in the postretirement plan. This remeasurement reduced the benefit obligation, resulting in the establishment of a prior service credit.
	(e)	In 2012, EEI's pension plan was amended to adjust the calculation of the future benefit obligation for all of its active management employees and certain union-represented employees from a traditional, final pay formula to a cash balance formula. Additionally, in 2012, EEI's management and union-represented postretirement medical benefit plans were amended to adjust for moving to a Medicare Advantage plan.
	(f)	Effective with the AER Acquisition, there was a reduction in employees who participated in the EEI management postretirement plan which resulted in a curtailment of the plan. EEI implemented an employee reduction program in 2012, which resulted in a curtailment of its pension and management postretirement benefit plans.
	(g)	The EEI union postretirement plan was over-funded as of December 31, 2013 and 2012 and the EEI management postretirement plan was over-funded as of December 31, 2013, which was included in our balance sheets in “Other assets.”
	The following table presents the assumptions used to determine our benefit obligations at December 31, 2013 and 2012:
			Pension Benefits						Postretirement Benefits
			2013			2012			2013			2012
	Discount rate at measurement date (a)		4.82	%		4	%		4.78	%		4	%
	Increase in future compensation (a)		3.5	%		4.48	%		3.5	%		4.41	%
	Ameren - Medical cost trend rate (initial)		N/A			N/A			N/A			5	%
	Ameren - Medical cost trend rate (ultimate)		N/A			N/A			N/A			5	%
	Ameren - Years to ultimate rate		N/A			N/A			N/A			0
	EEI - Medical cost trend rate (initial)		N/A			N/A			7.75	%		7.96	%
	EEI - Medical cost trend rate (ultimate)		N/A			N/A			4.5	%		4.5	%
	EEI - Years to ultimate rate		N/A			N/A			10 years			15 years
	_________________________________________
(a)	A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans at December 31, 2013. A weighted average rate of EEI’s and Ameren’s pension and postretirement plans at December 31, 2012.
Ameren, Dynegy and EEI determine their discount rate assumptions by identifying a theoretical settlement portfolio of high-quality corporate bonds sufficient to provide for their plan's projected benefit payments, pursuant to authoritative accounting guidance on the determination of discount rates used for defined benefit plan obligations.  For each plan, a single discount rate is then determined that results in a discounted value of that plan's benefit payments that equates to the market value of the selected bonds.
Funding
Pension benefits are based on the employees’ years of service and compensation. The Dynegy, Ameren and EEI pension plans are funded in compliance with income tax regulations and federal funding or regulatory requirements. As a result, we expect to fund EEI’s pension plan at a level equal to the greater of the pension expense or the legally required minimum contribution. In 2014, we expect to make contributions of $4 million to EEI's pension plan. In the aggregate, we expect to make contributions of $15 million to EEI’s pension plan over the next five years. Dynegy will contribute the portion of their pension related to Genco employees. These amounts are estimates and may change based on actual investment performance, changes in interest rates, changes in our assumptions, any pertinent changes in government regulations or any voluntary contributions.
The following table presents the cash contributions made to our defined benefit retirement plans during 2013, 2012 and 2011:
		Pension Benefits
(amounts in millions)		2013				2012				2011
Ameren allocation (a)		$	5			$	4			$	4
EEI		10				7				8
Total		$	15			$	11			$	12
_________________________________________
(a)	Represents an allocation of our share of cash contributions associated with our participation in Ameren’s pension plans.
Our current funding policies are to forego further contributions to their postretirement benefit plans, except as necessary to fund benefit payments. Employer contributions to our postretirement plans were less than $1 million for each year ended December 31, 2013, 2012 and 2011.
Investment Strategy and Policies
Since we received an allocation, not a specific assignment, of Ameren’s and Dynegy’s single-employer plan assets, the asset related disclosures below focus on EEI’s plan assets, which are all specifically assigned to us and were retained by us after the AER Acquisition. In connection with the AER Acquisition, as of December 2, 2013, Ameren retained all of the plan assets within its single-employer pension and postretirement plans.
EEI manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. EEI’s goal is to earn the highest possible return consistent with its tolerance for risk, which is monitored by EEI’s management and board of directors. EEI delegates investment management to specialists in each asset class. As appropriate, EEI provides its investment managers with guidelines that specify allowable and prohibited investment types and regularly monitor manager performance and compliance with investment guidelines.
The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class were estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, EEI adjusted the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns and for the effect of expenses paid from plan assets. EEI will utilize an expected return on plan assets for its pension plan assets of 6.25% in 2014. EEI will utilize an expected return on plan assets for its postretirement plan assets of 6.50% for EEI union employees and 5.50% for EEI management employees in 2014.
EEI strives to assemble a portfolio of diversified assets that does not create a significant concentration of risks. EEI’s management develops asset allocation guidelines between asset classes, and it creates diversification through investments in assets that differ by type (equity or debt). The diversification of assets is displayed in the target allocation table below. EEI’s management also routinely rebalances the plan assets to adhere to the diversification goals. The following table presents EEI’s target allocations for 2014 and EEI’s pension and postretirement plans’ asset categories as of December 31, 2013 and 2012.
Asset Category		Target Allocation			Percentage of Plan Assets at December  31,
		2014			2013			2012
Pension Plan:
Equity securities		60	%		61	%		59	%
Debt securities		40	%		39	%		38	%
Cash		—	%		—	%		3	%
Total		100	%		100	%		100	%
Postretirement Plans:
Equity securities		60	%		60	%		62	%
Debt securities		40	%		38	%		36	%
Cash		—	%		2	%		2	%
Total		100	%		100	%		100	%
Fair Value Measurements of Plan Assets
Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 2013. The fair value of an asset is the amount that would be received upon sale in an orderly transaction between market participants at the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. The carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments. Investments traded in active markets on national or international securities exchanges are valued at closing prices on the last business day on or before the measurement date. Securities traded in OTC markets are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency.
As described above, a portion of Dynegy’s pension plan assets is allocated to us as of December 31, 2013. The amount of Dynegy pension plan assets allocated to us for financial reporting purposes as of December 31, 2013, was less than $1 million based on pensionable salaries. The following table sets forth, by level within the fair value hierarchy discussed in Note 9—Fair Value Measurements, the EEI pension plan assets measured at fair value as of December 31, 2013:
(amounts in millions)		Quoted Prices in				Significant Other				Significant Other			Total
		Active Markets for				Observable Inputs				Unobservable
		Identified Assets				(Level 2)				Inputs
		(Level 1)								(Level 3)
Cash and cash equivalents		$	—			$	—			$	—		$	—
Equity securities:
U.S. large capitalization		—				26				—			26
U.S. small capitalization		—				14				—			14
International		—				6				—			6
Debt Securities		—				29				—			29
Total		$	—			$	75			$	—		$	75
As described above, a portion of Ameren’s pension plan assets was allocated to us as of December 31, 2012. The amount of Ameren pension plan assets allocated to us for financial reporting purposes as of December 31, 2012, was $117 million based on pensionable salaries. The following table sets forth, by level within the fair value hierarchy discussed in Note 9—Fair Value Measurements, the EEI pension plan assets measured at fair value as of December 31, 2012:
(amounts in millions)		Quoted Prices in				Significant Other				Significant Other			Total
		Active Markets for				Observable Inputs				Unobservable
		Identified Assets				(Level 2)				Inputs
		(Level 1)								(Level 3)
Cash and cash equivalents		$	—			$	2			$	—		$	2
Equity securities:
U.S. large capitalization		—				22				—			22
U.S. small capitalization		—				12				—			12
International		—				5				—			5
Debt securities		—				25				—			25
Total		$	—			$	66			$	—		$	66
As described above, a portion of Dynegy’s postretirement plan assets is allocated to us as of December 31, 2013. The amount of Dynegy postretirement plan assets allocated to us for financial reporting purposes as of December 31, 2013 was $1 million based on the number of our non-EEI employees. The following table sets forth, by level within the fair value hierarchy discussed in Note 9—Fair Value Measurements, the EEI postretirement benefit plans assets measured at fair value as of December 31, 2013:
(amounts in millions)		Quoted Prices in				Significant Other				Significant Other			Total
		Active Markets for				Observable Inputs				Unobservable
		Identified Assets				(Level 2)				Inputs
		(Level 1)								(Level 3)
Cash and cash equivalents		$	1			$	—			$	—		$	1
Equity securities:
U.S. large capitalization		33				—				—			33
International		8				—				—			8
Debt securities:
U.S. treasury and agency securities		13				1				—			14
Municipal bonds		—				5				—			5
Corporate bonds		—				6				—			6
Total		$	55			$	12			$	—		$	67
As described above, a portion of Ameren’s postretirement plan assets was allocated to us as of December 31, 2012. The amount of Ameren postretirement plan assets allocated to us for financial reporting purposes as of December 31, 2012 was $21 million based on the number of our non-EEI employees. The following table sets forth, by level within the fair value hierarchy discussed in Note 9—Fair Value Measurements, the EEI postretirement benefit plans assets measured at fair value as of December 31, 2012:
(amounts in millions)		Quoted Prices in				Significant Other				Significant Other			Total
		Active Markets for				Observable Inputs				Unobservable
		Identified Assets				(Level 2)				Inputs
		(Level 1)								(Level 3)
Cash and cash equivalents		$	—			$	1			$	—		$	1
Equity securities:
U.S. large capitalization		32				—				—			32
International		7				—				—			7
Debt securities:
U.S. treasury and agency securities		—				11				—			11
Municipal bonds		—				5				—			5
Corporate bonds		—				6				—			6
Total		$	39			$	23			$	—		$	62
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 and Dynegy’s pension and postretirement benefit plans during 2013, 2012 and 2011:
(amounts in millions)		Pension Benefits				Postretirement Benefits
2013
Service cost		$	5			$	2
Interest cost		10				3
Expected return on plan assets		(13		)		(5		)
Amortization of:
Prior service cost		(1		)		(8		)
Actuarial loss		6				5
Settlements		1				—
Curtailment gain (a)		—				(26		)
Net periodic benefit cost		$	8			$	(29	)
2012
Service cost		$	5			$	3
Interest cost		10				6
Expected return on plan assets		(13		)		(6		)
Amortization of:
Prior service cost		(1		)		(3		)
Actuarial loss		6				4
Curtailment loss (b)		2				—
Net periodic benefit cost		$	9			$	4
2011
Service cost		$	6			$	3
Interest cost		11				6
Expected return on plan assets		(13		)		(6		)
Amortization of:
Prior service cost		—				(3		)
Actuarial loss		3				2
Net periodic benefit cost		$	7			$	2
_________________________________________
(a)	Represents EEI’s management postretirement benefit plans’ curtailment gain recognized due to a reduction of employees as a result of the AER Acquisition.
(b)	Represents EEI’s pension and management postretirement benefit plans’ curtailment loss recognized as a result of its 2012 employee reduction program.
In addition to the above net periodic benefit cost for pension benefits, we were allocated $1 million, $2 million and $1 million in net periodic benefit costs from Ameren Services employees doing work on our behalf during the period from January 1 through December 1, 2013 and the years ended December 31, 2012 and 2011, respectively. We were also allocated less than $1 million, $1 million and $1 million in net periodic benefit costs for postretirement benefits from Ameren Services employees doing work on our behalf during the period from January 1 through December 1, 2013 and the years ended December 31, 2012 and 2011, respectively.
The estimated amounts that will be amortized from accumulated OCI into net periodic benefit cost in 2014 are as follows:
(amounts in millions)		Pension Benefits (a)				Postretirement Benefits (a)
Prior service cost (credit)		$	—			$	(4	)
Net actuarial loss		1				3
Total		$	1			$	(1	)
_________________________________________
(a)	Includes only amounts for EEI’s plans.
The amortization of prior service cost is determined using a straight line amortization of the cost over the average remaining service period of employees expected to receive benefits under the Plan.
The expected pension and postretirement benefit payments for expected future service, as of December 31, 2013, are as follows:
(amounts in millions)		Pension Benefits (a)				Postretirement Benefits (a)
2014		$	14			$	3
2015		$	6			$	3
2016		$	7			$	3
2017		$	7			$	3
2018		$	7			$	3
2019 - 2023		$	32			$	14
_________________________________________
(a)	Includes only amounts for EEI’s plans.
The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2013, 2012 and 2011:
		Pension Benefits									Postretirement Benefits
		2013			2012			2011			2013		2012			2011
Discount rate (a)		(b)			4.36	%		5.33	%		(c)		4.29	%		5.39	%
Expected return on plan assets (a)		7.65	%		7.84	%		8	%		7.59	%	7.87	%		7.93	%
Increase in future compensation (a)		(d)			3.7	%		3.7	%		(e)		3.86	%		3.83	%
Ameren - Medical cost trend rate (initial)		N/A			N/A			N/A			5	%	5.5	%		6	%
Ameren - Medical cost trend rate (ultimate)		N/A			N/A			N/A			5	%	5	%		5	%
Ameren - Years to ultimate rate		N/A			N/A			N/A			0		1 year			2 years
EEI - Medical cost trend rate (initial)		N/A			N/A			N/A			(f)		8.3	%		8.65	%
EEI - Medical cost trend rate (ultimate)		N/A			N/A			N/A			4.5	%	4.5	%		4.5	%
EEI - Years to ultimate rate		N/A			N/A			N/A			(g)		15 years			16 years
_________________________________________
(a)	A weighted average rate of EEI’s and Ameren’s pension and postretirement plans.
(b)	The discount rate used for EEI’s pension plan was 4.00% and 4.67% for the period from January 1, 2013 through December 1, 2013 and the period from December 2, 2013 through December 31, 2013, respectively. The discount rate used for Ameren’s pension plans was 4.00% for the period from January 1, 2013 through December 1, 2013.
(c)	The discount rate used for EEI’s postretirement plans was 4.00% for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 4.00% for EEI union employees and 4.75% for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively. The discount rate used for Ameren’s postretirement plans was 4.00% for the period from January 1, 2013 through December 1, 2013.
(d)	The average rate of compensation increase used for EEI’s pension plan was 5.97% and 3.50% for the period from January 1, 2013 through December 1, 2013 and the period from December 2, 2013 through December 31, 2013, respectively. The average rate of compensation increase used for Ameren’s pension plans was 3.50% for the period from January 1, 2013 through December 1, 2013.
(e)	The average rate of compensation increase used for EEI’s postretirement plans was 6.35% for EEI union employees and 3.81% for EEI management employees for the period from January 1, 2013 through December 1, 2013 and 6.35% for EEI union employees and 3.50% for EEI management employees and the period from December 2, 2013 through December 31, 2013, respectively. The average rate of compensation increase used for Ameren’s postretirement plans was 3.50% for the period from January 1, 2013 through December 1, 2013.
(f)	The initial medical cost trend rate used for EEI’s postretirement plans was 7.96% for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 7.96% for EEI union employees and 7.75% for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively.
(g)	The years to ultimate trend rate used for EEI’s postretirement plans was 14 years for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 14 years for EEI union employees and 10 years for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively.
The table below reflects the sensitivity to potential changes in key assumptions:
		Pension Benefits (a)				Postretirement Benefits (a)
(amounts in millions)		Service Cost		Projected		Service Cost				Postretirement
		and Interest		Benefit		and Interest				Benefit
		Cost		Obligation		Cost				Obligation
1.00% increase in annual medical trend		N/A		N/A		$	1			$	5
1.00% decrease in annual medical trend		N/A		N/A		$	—			$	(4	)
_________________________________________
(a)	Includes amounts for EEI’s plans and our participation in Dynegy’s plans.
Other
Ameren sponsored a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible employees, including our employees, prior to December 2, 2013, the date of the AER Acquisition. Effective December 2, 2013, our employees, excluding the EEI employees, participate in the Dynegy Inc. 401(k) Plan. Prior to December 31, 2013, the EEI Bargaining Unit 401(k) Plan covered all eligible EEI union employees and the EEI Management 401(k) Plan covered all eligible EEI management employees. Effective January 1, 2014, these plan benefits were frozen. Contributions stopped as of that date and EEI participants became eligible to participate in the Dynegy Inc. 401(k) Plan. These 401(k) plans allowed employees to contribute a portion of their compensation in accordance with specific guidelines. The plan sponsor matched a percentage of the employee contributions up to certain limits. Our portion of the matching contribution to the Ameren 401(k) plan was $1 million, $1 million and $2 million for the period from January 1 through December 1, 2013 and the years ended December 31, 2012 and 2011, respectively. The matching contribution to the EEI 401(k) plans was $1 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
INCOME TAXES	'
	INCOME TAXES
	Our loss before income taxes was $254 million and $69 million for the year ended December 31, 2013 and 2012, respectively. Our income before income taxes was $77 million for the year ended December 31, 2011. The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate:
			Year Ended December 31,
	(amounts in millions)		2013			2012			2011
	Statutory federal income tax rate:		35	%		35	%		35	%
	Increases (decreases) from:
	Tax credits		—			(2	)		(1	)
	Amortization of investment tax credit		—			—			(1	)
	State tax		6			7			6
	Production activities deduction		—			—			3
	Reserve for uncertain tax positions		—			2			—
	Acquisition adjustment (a)		(15	)		—			—
	Effective income tax rate		26	%		42	%		42	%
	_________________________________________
	(a)	Acquisition adjustment is primarily the result of the loss of expected benefits from the NOL carryforward in existence at the Acquisition Date due to IRC Section 382 limits.
	The following table presents the components of income tax expense (benefit):
			Year Ended December 31,
	(amounts in millions)		2013				2012				2011
	Current taxes:
	Federal		$	(50	)		$	(15	)		$	(21	)
	State		(14		)		(5		)		(7		)
	Deferred taxes:
	Federal		6				(6		)		43
	State		(6		)		(2		)		18
	Deferred investment tax credits, amortization		(1		)		(1		)		(1		)
	Total income tax expense (benefit)		$	(65	)		$	(29	)		$	32
	The Illinois corporate income tax rate increased from 7.3% to 9.5%, starting in January 2011. The tax rate is scheduled to decrease to 7.75% in 2015, and it is scheduled to return to 7.3% in 2025. This corporate income tax rate increase in Illinois increased current income tax expense in 2011 by $3 million.
	The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences:
			December 31,
	(amounts in millions)		2013				2012
	Accumulated deferred income taxes, net liability (asset):
	Plant related		$	541			$	424
	Deferred employee benefit costs		(24		)		(37		)
	ARO		(16		)		(28		)
	Other (a)		38				(36		)
	Total net accumulated deferred income tax liabilities (b)		$	539			$	323
	_________________________________________
	(a)	Included deferred tax assets related to net operating loss and tax credit carryforwards as of December 31, 2012.
	(b)	Includes $11 million in “Other current assets” on the balance sheet as of December 31, 2012.
	Uncertain Tax Positions
	A reconciliation of the change in the unrecognized tax benefit balance is as follows:
			Year Ended December 31,
	(amounts in millions)		2013				2012				2011
	Unrecognized tax benefits - beginning of year		$	6			$	9			$	20
	Increases based on tax positions prior to current year		2				1				1
	Decreases based on tax positions prior to current year		(3		)		(2		)		(12		)
	Increases based on tax positions related to current year		—				—				1
	Decreases based on tax positions related to current year		(1		)		(1		)		—
	Adjustment of balance due to change in ownership		(3		)		—				—
	Decreases related to the lapse of statute of limitations		(1		)		(1		)		(1		)
	Unrecognized tax benefits - end of year		$	—			$	6			$	9
	Total unrecognized tax benefits (detriments) that, if recognized, would affect the effective tax rates		$	—			$	—			$	1
	Interest charges (income) and penalties accrued on tax liabilities on a pretax basis are recognized as interest charges (income) or miscellaneous expense, respectively, in the statements of income (loss).
	A reconciliation of the change in the liability for interest on unrecognized tax benefits is as follows:
			Year Ended December 31,
	(amounts in millions)		2013				2012				2011
	Liability for interest - beginning of year		$	1			$	1			$	2
	Interest charges (income)		—				—				(1		)
	Adjustment of balance due to change in ownership		(1		)		—				—
	Liability for interest - end of year		$	—			$	1			$	1
	As of December 31, 2013, 2012 and 2011, we accrued no amount for penalties with respect to unrecognized tax benefits.
	Upon the AER Acquisition, we are included in the consolidated tax returns of Dynegy. Under U.S. federal income tax law, Dynegy files consolidated income tax returns for itself and its subsidiaries. Dynegy is responsible for the federal tax liabilities of its subsidiaries, which include the income and business activities of the ring-fenced entities and Dynegy’s other affiliates.  Prior to the AER Acquisition, we were included in the consolidated federal and state income tax returns of Ameren Corporation. Genco and Ameren Corporation were parties to a tax sharing agreement that provided that the amount of tax recognized was similar to that which would have been owed had we been separately subject to tax. Genco and Dynegy have entered into a new tax sharing agreement that also provides that we recognize taxes based on a separate company income tax return basis, as defined in the agreement.  As of December 31, 2013 we owed approximately $1 million to Dynegy pursuant to the new tax sharing agreement.
	Upon the AER Acquisition, we experienced an “ownership change,” as defined under IRC Section 382 and Ameren recognized a worthless stock loss on the basis of its stock in the Company. As a result of both the ownership change and the worthless stock loss, the Company reduced its NOLs to zero and reduced other tax basis of assets by $433 million. The total amount of NOLs that could be used in any one year following such ownership change was limited such that all of our NOLs cannot be used against future taxable income. The adjustments to the NOLs and tax attributes resulted in a charge to paid-in capital at the Acquisition Date of $178 million and a reduction to our income tax benefit for 2013 in the amount of $39 million.
In 2011, a final settlement for the years 2005 and 2006 was reached with the Internal Revenue Service. It resulted in a reduction in our uncertain tax liabilities of $4 million.
Genco is currently under federal audit for the periods 2007 through 2011. State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. As a result of the AER Acquisition, we are indemnified by Ameren for any federal or state tax adjustment for tax periods prior to December 2, 2013.

Derivative_Financial_Instrumen

Derivative Financial Instruments

12 Months Ended

Dec. 31, 2013

Derivative Instrument Detail [Abstract]

'

DERIVATIVE FINANCIAL INSTRUMENTS

'

DERIVATIVE FINANCIAL INSTRUMENTS

The nature of our business necessarily involves market and financial risks. Specifically, we are exposed to commodity price variability related to our power generation business. Our commercial team manages these commodity price risks with financially settled and other types of contracts consistent with our commodity risk management policy. Our treasury team manages our financial risks and exposures associated with interest expense variability.

Our commodity risk management strategy gives us the flexibility to sell energy and capacity and purchase fuel through a combination of spot market sales and near-term contractual arrangements (generally over a rolling one- to three-year time frame). Our commodity risk management goal is to protect cash flow in the near-term while keeping the ability to capture value longer-term.

We manage commodity price risk by entering into capacity forward sales arrangements, tolling arrangements, Reliability Must Run contracts, fixed price coal purchases and other arrangements that do not receive recurring fair value accounting treatment because these arrangements do not meet the definition of a derivative or are designated as “normal purchase, normal sale.” As a result, the gains and losses with respect to these arrangements are not reflected in the consolidated statements of operations until the delivery occurs.

We did not have a material amount of outstanding derivative positions as of December 31, 2013. The following table presents open gross derivative commodity contract volumes by commodity type as of December 31, 2013 and 2012:

Quantity (in millions)

Commodity

2013

2012

Coal (in tons)

—

5

Fuel oils (in gallons) (a)

—

40

Natural gas (in mmbtu) (b)

—

42

Power (in MWh)

—

—

________________________________________

(a)

Fuel oils consist of heating and crude oil.

(b)

Amounts include commodity contracts classified as held for sale.

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. Please read Note 9—Fair Value Measurements for further discussion of our methods of assessing the fair value of derivative instruments. For our physical contracts that 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 historically reviewed the contract to determine if it qualifies for hedge accounting. In 2013, we discontinued the use of cash flow hedge accounting. Contracts that previously qualified for cash flow hedge accounting were recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurred, to the extent the hedge was effective. To the extent the hedge was ineffective, the related changes in fair value were charged or credited to operating income (loss) in the period in which the change occurred. When the contract is settled or delivered, the net gain or loss is recorded to operating income (loss).

Certain derivative contracts were entered into on a regular basis as part of our risk management program but did not qualify for, or we did not choose to elect, the NPNS exception or hedge accounting. Such contracts were recorded at fair value, with changes in fair value charged or credited to the statements of operations in the period in which the change occurred.

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.

We did not have any derivative instruments as of December 31, 2013. The following table presents the carrying value of all derivative instruments as reported in our balance sheets as of December 31, 2012:

(amounts in millions)

Year Ended December 31, 2012

Derivative assets not designated as hedging instruments

Commodity contracts:

Coal

Other assets

$

1

Fuel oils

Other current assets

2

Other assets

1

Natural gas

Other current assets

4

Total assets

$

8

Derivative liabilities not designated as hedging instruments

Commodity contracts:

Coal

Other current liabilities

$

7

Other deferred credits and liabilities

3

Fuel oils

Other current liabilities

1

Other deferred credits and liabilities

1

Natural gas

Liabilities held for sale

3

Total liabilities

$

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 December 31, 2013 and 2012. These interest rate swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with our April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. Over the next 12 months, less than $1 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.

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 one of five groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of 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.

(amounts in millions)

Coal

Commodity

Electric

Financial

Oil and Gas

Total

Producers

Marketing

Utilities

Companies

Companies

Companies

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 December 31, 2013, we held no collateral to reduce exposure. As of December 31, 2012, we held other collateral which consisted of letters of credit in the amount of $1 million to reduce exposure. The following table presents the potential loss after consideration of the application of master trading and netting agreements and collateral held as of December 31, 2012:

(amounts in millions)

Coal

Commodity

Electric

Financial

Oil and Gas

Total

Producers

Marketing

Utilities

Companies

Companies

Companies

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 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 December 31, 2013, and (2) those counterparties with rights to do so requested collateral:

(amounts in millions)

Aggregate Fair Value of

Cash

Potential Aggregate Amount of

Derivative Liabilities (a)

Collateral Posted

Additional Collateral Required

2012 (b)

$

48

$

—

$

31

__________________________________________

(a)

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

(b)

Includes amounts classified as held for sale.

Cash Flow Hedges

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

(amounts in millions)

Gain (Loss)

Location of (Gain) Loss

(Gain) Loss

Location of Gain (Loss)

Gain (Loss)

Recognized in OCI (a)

Reclassified from

Reclassified from

Recognized in Income (c)

Recognized

Accumulated OCI into

Accumulated OCI

in Income (c)

Income (b)

into Income (b)

2013

Interest rate (d)

$

—

Interest Charges

$

1

Interest Charges

$

—

2012

Interest rate (d)

$

—

Interest Charges

$

1

Interest Charges

$

—

__________________________________________

(a)

Effective portion of gain (loss).

(b)

Effective portion of (gain) loss on settlements.

(c)

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

(d)

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

Other Derivatives

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

Location of Gain (Loss)

Gain (Loss) Recognized

Recognized in Income

in Income

(amounts in millions)

2013

2012

Coal

Operating Expenses - Fuel

$

9

$

(9

)

Fuel oils

Operating Expenses - Fuel

(1

)

(9

)

Natural gas (generation) (a)

Operating Expenses - Fuel

(1

)

—

Power

Operating Revenues

—

—

Total

$

7

$

(18

)

________________________________________

(a)

Includes amounts classified as held for sale.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 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 reasonableness review, 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.
	We did not have any significant financial assets and liabilities classified as Level 3 in the fair value hierarchy at December 31, 2013. 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 did not have a material amount of outstanding derivative positions as of December 31, 2013. The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012:
				Quoted Prices in			Significant Other			Significant Other			Total
				Active Markets for			Observable			Unobservable
				Identical Assets			Inputs			Inputs
				or Liabilities			(Level 2)			(Level 3)
				(Level 1)
	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.
	The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
			Year Ended December 31,
	(amounts in millions)		2013			2012
	Fuel oils:
	Beginning balance at January 1		$	1		$	1
	Realized and unrealized gains (losses):
	Included in earnings		—			—
	Total realized and unrealized gains (losses)		—			—
	Purchases		—			—
	Settlements		(1		)	—
	Transfers into Level 3		—			1
	Transfers out of Level 3		—			(1		)
	Ending balance at December 31		$	—		$	1
	Change in unrealized gains (losses) related to assets/liabilities held at December 31		$	—		$	—
	Transfers into 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 year ended December 31, 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 years ended December 31, 2013 and 2012, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts.
	Please read Note 6—Retirement Benefits for further discussion regarding our participation in Dynegy’s and EEI’s pension and postretirement benefit plans.
	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:
			December 31, 2013						December 31, 2012
	(amounts in millions)		Carrying Amount			Fair Value			Carrying Amount			Fair Value
	Long-term debt (including current portion)		$	824		$	683		$	824		$	618

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
COMMITMENTS AND CONTINGENCIES	'
	COMMITMENTS AND CONTINGENCIES
	Legal Proceedings
	We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses. Material legal and administrative proceedings include the following:
	New Source Review and Clean Air Litigation. Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the CAA when the plants implemented modifications. The EPA's initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment.
	Coffeen, Newton and Joppa Facilities. Commencing in 2005, we received a series of information requests from the EPA pursuant to Section 114(a) of the CAA seeking detailed operating and maintenance history data with respect to our Coffeen, Newton and Joppa facilities. In August 2012, the EPA issued a Notice of Violation alleging that projects performed in 1997, 2006 and 2007 at the Newton facility violated PSD, Title V permitting and other requirements. 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 facility Notice of Violation.
	Ultimate resolution of these matters could have a material adverse impact on our future financial condition, results of operations, and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve these matters.
	Variance. In January 2014, an environmental group filed a petition for review in the Illinois Fourth District Appellate Court of the IPCB’s November 2013 decision and order granting IPH a variance extending the applicable compliance dates for MPS SO2 emission limits. We believe the petition for review is without merit and on January 17, 2014, IPH filed a Motion to Dismiss. On February 24, 2014, the Fourth District Appellate Court granted the motion and dismissed the appeal.
	Newton and Coffeen Facilities’ Groundwater. Hydrogeologic investigations of the CCR surface impoundments have been performed at the Newton and Coffeen facilities.  Groundwater monitoring results indicate that the CCR surface impoundments at each of the facilities potentially impact onsite groundwater.
	In 2012, the Illinois Environmental Protection Agency (“Illinois EPA”) issued violation notices with respect to groundwater conditions at the Newton and Coffeen facilities’ ash pond systems. In February 2013, the Illinois EPA provided written notice that it may pursue legal action with respect to each of these matters through referral to the Illinois Office of the Attorney General. At this time we cannot reasonably estimate the costs or range of costs of resolving the Newton and Coffeen enforcement matters, but resolution of these matters may cause us to incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows.
	Environmental Matters
	We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. The ongoing operation of existing or new electric generation and transmission facilities, involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.
	In addition to existing laws and regulations, including the Illinois MPS that applies to our coal-fired facilities, the EPA is developing environmental regulations that will have a significant impact on the electricity generators. These regulations could be particularly burdensome for certain companies, including ours, that operate coal-fired facilities. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of GHG emissions from new facilities; revised NAAQS for SO2, NOx and fine particulates; the CSAPR, which would have required further reductions of SO2 and NOx emissions from facilities; a regulation that governs management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, metals, and acid gases from facilities; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; new standards for cooling water intake structures at facilities; and new effluent standards applicable to discharges from steam-electric generating units. The EPA is expected to propose CO2 limits for existing fossil-fuel fired electric generation units in 2014. 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/or increased operating costs over the next five to ten years. Compliance with these environmental laws and regulations could be prohibitively expensive. If they are, these regulations could require us to close or to significantly alter the operation of our facilities, 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.
	We expect to incur capital costs of $45 million in 2014 to comply with existing environmental regulations, including the CAIR, the MPS and the final MATS rule. In addition, these estimated costs assume that CCR will continue to be regarded as nonhazardous. The estimate does not include the EPA’s proposed CCR regulations, the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures or effluent standards applicable to steam-electric generating units that the EPA proposed in April 2013, as the technology and compliance requirements ultimately to be selected in these final rules are not yet known. The estimate could change significantly depending upon a variety of factors including:
	•	additional or modified federal, state or local requirements;
	•	further regulation of GHG emissions;
	•	revisions to CAIR or reinstatement of CSAPR;
	•	delays or accelerations of rulemaking and implementation by the EPA or state agencies;
	•	new NAAQS, new standards intended to achieve NAAQS or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions;
	•	additional 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;
	•	variations in costs of material or labor; and
	•	alternative compliance strategies or investment decisions.
	The following sections describe the more significant environmental rules that affect or could affect our operations:
	Clean Air Act
	Both federal and state laws require significant reductions in SO2 and 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 required generating facilities in 28 states, including Illinois, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO2 emissions, annual 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. The CSAPR was to become effective on January 1, 2012, for SO2 and annual NOx reductions and on May 1, 2012, for ozone season NOx reductions, with further reductions in 2014. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR and, in August 2012, the court 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 the 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 CSAPR is reinstated following completion of judicial review.
	In December 2011, the EPA issued the MATS, which establish emission limits for mercury and other hazardous air pollutants, such as acid gases and metals, equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards establish limits for hydrogen chloride emissions, which were not regulated previously, and for the first time require continuous monitoring systems or quarterly emission testing for hydrogen chloride, mercury and particulate matter that are not currently in place. The MATS do not require a specific control technology to achieve the emission limits. The MATS will apply to each unit at a coal-fired power plant; however, emission compliance can be achieved by averaging emissions from similar electric generating units at the same power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016.
	Separately, in December 2012, the EPA issued a final rule that made the NAAQS 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 facilities but could require reductions in SO2 and NOx emissions. Compliance with the final rule is required by 2020, unless an extension of time to achieve compliance is granted. We continue to evaluate the new standard while the state of Illinois develops its attainment plans.
	In September 2011, the EPA announced that it was implementing the 2008 NAAQS for ozone. The state of Illinois will be required to develop an attainment plan to comply with the 2008 NAAQS for ozone, which could result in additional emission control requirements for power plants by 2020. The EPA also is in the process of completing its ongoing five-year review of the current ozone NAAQS, which may result in a more stringent standard. Rulemaking action concerning the ozone NAAQS is not anticipated until 2015. We continue to assess the impacts of ozone NAAQS developments.
	In July 2013, the EPA issued a final rule designating portions of the United States, including parts of Illinois, as nonattainment for the one-hour SO2 NAAQS based on existing ambient monitoring data. The designations became effective in October 2013, and the states must develop plans within 18 months to reduce emissions so that they can achieve the ambient air quality standard within five years. None of our facilities are located in areas that were initially designated nonattainment by the EPA. The EPA expects to complete SO2 nonattainment area designations by 2018 for areas that currently lack sufficient monitoring data. We continue to assess the impacts of these SO2 NAAQS developments.
	In September 2012, the IPCB granted AER a variance to extend the applicable compliance dates for MPS SO2 emission limits through December 31, 2019, subject to certain conditions described below. The variance provides additional time for economic recovery and related power price improvements necessary to support the installation of flue gas desulfurization (i.e. scrubber) systems at the Newton facility such that the AER coal-fired fleet in Illinois can meet the MPS system-wide SO2 limit. The IPCB approved AER's proposed plan to restrict its SO2 emissions through 2014 to levels lower than those required by the MPS to offset any environmental impact from the variance. The IPCB’s order also included a schedule of milestones for completion of various aspects of the installation of the Newton scrubber systems. 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.
	In May 2013, IPH and AER filed a request with the IPCB to transfer the September 2012 variance to IPH. The IPCB denied the request on procedural grounds but indicated that IPH could file its own request for variance relief. In July 2013, IPH, along with certain co-petitioners, filed such a petition for variance relief. In November 2013, the IPCB approved the variance petition. The November 2013 variance includes the same project milestones for the completion of the Newton scrubber project as the September 2012 variance and also requires, as was proposed by IPH, additional environmental protections in the form of enforceable commitments to cap the IPH system’s SO2 emissions over the period from the fourth quarter 2013 through December 31, 2020, retire IPRG’s Edwards Unit 1 as soon as permitted by the MISO, and, during the variance period, use only low sulfur coal at the Newton, Joppa and Edwards facilities and optimize operation of the existing scrubbers at our Coffeen facility and IPRG’s Duck Creek facility.
	In January 2014, an environmental group filed a petition in the Illinois Fourth District Appellate Court seeking review of the IPCB’s November 2013 decision and order granting the variance relief. We believed the petition for review was without merit and on January 17, 2014, IPH filed a Motion to Dismiss. On February 24, 2014, the Fourth District Appellate Court granted the motion and dismissed the appeal.
	To comply with the MPS and other air emissions laws and regulations, we have installed or are installing equipment designed to reduce emissions of mercury, NOx, and SO2. We have installed two scrubbers at the Coffeen facility. Two additional scrubbers are being constructed at the Newton facility. 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 facilities 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 CAIR allowances for 2014 to avoid needing to make external purchases to comply with these programs.
	GHG Regulation
	State and federal authorities, including the United States Congress, have considered initiatives to limit GHG emissions and to address global climate change. Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. Our emissions of GHG vary among our facilities, 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 GHG emissions, including CO2, endanger human health and welfare and that emissions of GHG from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that GHG 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 GHG in any air permit application.
	Recognizing the difficulties presented by regulating at once virtually all emitters of GHG, the EPA issued the “Tailoring Rule,” which established new higher emission thresholds beginning in January 2011, for regulating GHG emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have GHG-specific provisions added to its permits upon renewal. Currently, Genco facilities have operating permits that, when renewed, may be modified to address GHG emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of GHG over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to control GHG emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their GHG 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 GHG from stationary sources, including power plants, as a result of the EPA’s determination to regulate GHG 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. This proposed NSPS for CO2 emissions would apply only to new fossil-fuel fired electric facilities and therefore does not affect any of our existing facilities. A final rule is expected in 2014. In addition, the Obama Administration 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 damages resulting from global climate change. In March 2012, the United States District Court for the Southern District of Mississippi dismissed the Comer v. Murphy Oil lawsuit, which alleged that CO2 emissions from several industrial companies, including our facilities, 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. The plaintiffs did not seek review by the United States Supreme Court.
	Future federal and state legislation or regulations that mandate limits on the emission of GHG 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 facilities 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 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 should have triggered various permitting requirements and the installation of pollution control equipment.
	Commencing in 2005, we received a series of information requests from the EPA pursuant to Section 114(a) of the Clean Air Act. The requests sought detailed operating and maintenance history data with respect to our Coffeen, Newton, and Joppa facilities. In August 2012, we received a Notice of Violation from the EPA alleging violations of permitting requirements at our Newton facility, including Title V of the Clean Air Act. The EPA contends that projects performed in 1997, 2006 and 2007 at our Newton facility 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 facility Notice of Violation. We are unable to predict the outcome of this matter.
	Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be incurred.
	Clean Water Act
	In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants. 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 would also require 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 2014, with compliance expected within eight years thereafter. Our facilities with cooling water systems are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities, as other technology options potentially could meet the site-specific standards. We are currently evaluating the proposed rule, and our assessment of the proposed rule's impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule, if adopted, could have a material adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our facilities.
	In April 2013, the EPA announced its proposal to revise the effluent limitation guidelines applicable to steam electric generating units. Effluent limitation guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The proposed revisions target wastewater streams associated with flue gas desulfurization (i.e., scrubbers), fly ash, bottom ash, flue gas 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 adopted 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. The EPA expects to issue a final rule in 2014. The proposed rule, if adopted, may cause us to incur significant costs.
	Ash Management
	There has been activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our facilities. 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 is expected to issue a final CCR rule in late 2014. 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 Coffeen and Newton ash pond systems. In February 2013, the Illinois EPA provided written notice that it may pursue legal action with respect to each of these matters through referral to the Illinois Office of the Attorney General. In April 2013, AER filed a proposed rulemaking with the IPCB which, if approved, would provide for the systematic and eventual closure of AER’s ash ponds. In October 2013, the Illinois EPA filed a proposed rulemaking with the IPCB that would establish processes governing monitoring, preventative response, corrective action and closure of CCR surface impoundments at all power generating facilities in Illinois. The AER rulemaking has been stayed to allow the Illinois EPA proposed rulemaking to proceed. At this time we cannot reasonably estimate the costs or range of costs of resolving the Newton and Coffeen enforcement matters, but resolution of these matters may cause us to incur significant costs that could have a material adverse effect on our results of operations, financial position, and liquidity. During the first quarter 2013, we revised our ARO fair value estimates relating to ash ponds. Please read Note 1—Summary of Significant Accounting Policies for further discussion related to our AROs.
	Guaranty
	Guaranty Agreement. In connection with the AER Acquisition, Genco has provided a Guaranty Agreement of certain obligations of IPH up to $25 million. Concurrently with the closing of the Transaction Agreement on December 2, 2013, Genco entered into the Guaranty Agreement, capped at $25 million in favor of Ameren, pursuant to which Genco guaranteed for a period of two years after the closing (subject to certain exceptions), up to $25 million with respect to IPH’s indemnification obligations and certain reimbursement obligations under the Transaction Agreement.
	Other Commitments
	In conducting our operations, we have routinely entered into long-term commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. These commitments have been typically associated with commodity supply arrangements, capital projects, reservation charges associated with firm transmission, transportation, storage and leases for office space, plant sites and power generation assets. The following describes the more significant commitments outstanding at December 31, 2013:
	Coal Commitments. At December 31, 2013, we had contracts in place to supply coal to our generation facilities with minimum commitments of $366 million through 2017.
	Coal Transportation. At December 31, 2013, we had coal transportation contracts in place through 2023 and rail car leases in place through 2026 with aggregate minimum commitments of $279 million.
Operating Leases. Our operating leases include minimum lease payment obligations of less than $1 million per year through 2018 associated with office leases.
Total rental expense included in operating expenses, for the years ended December 31, 2013, 2012 and 2011 was $4 million, $4 million and $2 million, respectively.
Other Obligations.  Our other obligations included severance and retention obligations of $3 million in connection with a reduction in workforce and $4 million over the next 26 years under a facilities service agreement to compensate an affiliated entity for additions made on our electric generating facilities.

Impairment_and_Other_Charges

Impairment and Other Charges	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
IMPAIRMENT AND OTHER CHARGES	'
	IMPAIRMENT AND OTHER CHARGES
	The following table summarizes the pretax charges recognized for the years ended December 31, 2013, 2012 and 2011:
	(amounts in millions)	Long-Lived		Emission		Total
		Assets and Related Charges		Allowances
	2013	$	199	$	—	$	199
	2012	$	70	$	—	$	70
	2011	$	34	$	1	$	35
	Each of the above charges was recorded in the statements of operations as “Impairment and other charges.” The impairment charges did not result in a violation of our debt covenants or counterparty agreements. Each of the charges is discussed below.
	Long-lived Assets
	We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we would recognize an impairment charge equal to the amount of the carrying value of the assets that exceeds its estimated fair value.
	We recorded impairment charges on our long-lived assets for the years ended December 31, 2011 and 2012, under a held and used model. We recorded additional impairment charges in 2013 under the held for sale model.
	Key assumptions used in the determination of estimated undiscounted cash flows of our long-lived assets tested for impairment under a held and used model included forward price projections for energy and fuel costs, the expected life or duration of ownership of the long-lived assets, environmental compliance costs and strategies, and operating costs. These assumptions are subject to a high degree of judgment and complexity. In comparison, impairment analysis under the held for sale model involves only comparison of the carrying cost of the asset group to the asset group’s estimated fair value less cost to sell and recording an impairment charge for any excess of that carrying value over the estimated fair value less cost to sell. We assess impairment at the lowest level of identifiable cash flows.
	We recorded a pretax charge to earnings of $199 million for the year ended December 31, 2013, to reflect the impairment of the Gas-Fired Facilities under a held for sale model. Fair value was based on the actual sales price of $138 million realized upon sale of the Gas-Fired Facilities to Medina Valley in October 2013. The 2013 impairment recorded was primarily related to the Gibson City and Grand Tower Gas-Fired Facilities as the Elgin facility was previously impaired (pretax charge to earnings of $70 million) under held and used accounting guidance during the fourth quarter of 2012. We also recorded an $82 million income tax benefit as a result of the 2013 impairment charge. In December 2011, we ceased operations of our Meredosia and Hutsonville facilities. As a result, we recorded a noncash pretax asset impairment charge of $26 million to reduce the carrying value of the Meredosia and Hutsonville facilities to their estimated fair values, a $4 million impairment of materials and supplies and $4 million for severance costs.
	We will continue to monitor the market price for power and the related impact on electric margin, our liquidity needs, and other events or changes in circumstances that indicate that the carrying value of our facilities may not be recoverable as compared to their undiscounted cash flows. We could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted future cash flows no longer exceed carrying values for long-lived assets. This may occur either as a result of factors outside our control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of our facilities, and also as a result of factors that may be within our control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell our facilities. As of December 31, 2013, the carrying value of long-lived assets exceeded their realizable fair value by an amount in excess of $1 billion.
	Intangible Assets
	In July 2011, the EPA issued the CSAPR, which created new allowances for SO2 and NOx emissions, and restricted the use of preexisting SO2 and NOx allowances to the acid rain program and to the NOx budget trading program, respectively. As a result, observable market prices for existing emission allowances declined materially. Consequently, we recorded a $1 million non-cash pretax impairment charge relating to emission allowances.
	The fair value of the SO2 and NOx emission allowances was based on observable and unobservable inputs, which were classified as Level 3 inputs for fair value measurements.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss) (Notes)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Accumulated Other Comprehensive Income	'
	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
	Changes in accumulated other comprehensive income (loss), net of tax, by component are as follows:
	(amounts in millions)		Year Ended December 31, 2013			Year Ended December 31, 2012
	Beginning of period		$	(40	)	$	(72	)
	Current period other comprehensive income:
	Actuarial gain and plan amendments (net of tax expense of $8 and $20, respectively)		12			28
	Amounts reclassified from accumulated other comprehensive income (loss):
	Reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges, net (net of tax benefit of zero and zero, respectively) (a)		1			1
	Amortization of unrecognized prior service cost and actuarial gain (loss) (net of tax expense of $1 and $2, respectively) (b)		1			3
	Amounts reclassified from accumulated other comprehensive income (loss) (net of tax benefit of $9 and zero, respectively) (c)		(13		)	—
	Total amounts reclassified from accumulated other comprehensive income (loss)		(11		)	4
	Net current period other comprehensive income (loss), net of tax		1			32
	AER Acquisition (net of tax expense of $20 and zero, respectively) (d)		28			—
	End of period		$	(11	)	$	(40	)
	__________________________________________
	(a)	Amount related to the reclassification of mark-to-market loss on cash flow hedging activities, net and was recorded in Interest Charges in our consolidated statements of operations.
	(b)	Amounts are associated with our defined benefit pension and other postretirement benefit plans and are included in the computation of net periodic pension cost. Please read Note 6—Retirement Benefits for further discussion.
	(c)	Amount related to the EEI curtailment gain on pension and postretirement benefit plans and was recorded in Other operations and maintenance in our consolidated statements of operations. Please read Note 6—Retirement Benefits for further discussion.
	(d)	Amount related to the transfer of certain defined benefit pension and other postretirement benefit plans as a part of the AER Acquisition. Please read Note 6—Retirement Benefits for further discussion.

Selected_Quarterly_Information

Selected Quarterly Information (Unaudited)	12 Months Ended
	Dec. 31, 2013
Selected Quarterly Financial Information [Abstract]	'
SELECTED QUARTERLY INFORMATION	'
	SELECTED QUARTERLY INFORMATION (Unaudited) (In millions)
	Quarter Ended		Operating		Operating Income (Loss) (a)			Net Income (Loss)			Net Income (Loss)
			Revenues								Attributable to
											Illinois Power
											Generating Company
	March 31, 2013		$	187	$	(204	)	$	(129	)	$	(129	)
	March 31, 2012		$	194	$	13		$	(3	)	$	(1	)
	June 30, 2013		$	187	$	(25	)	$	(22	)	$	(22	)
	June 30, 2012		$	194	$	(4	)	$	(6	)	$	(4	)
	September 30, 2013		$	275	$	—		$	(5	)	$	(5	)
	September 30, 2012		$	218	$	34		$	11		$	13
	December 31, 2013		$	155	$	16		$	(33	)	$	(32	)
	December 31, 2012		$	202	$	(60	)	$	(42	)	$	(41	)
	_________________________________________
	(a)	Includes pretax “Impairment and other charges” of $199 million and $70 million recorded during the years ended December 31, 2013 and 2012, respectively. Please read Note 11—Impairment and Other Charges for further discussion.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Cash and Cash Equivalents	'
	Cash and Cash Equivalents
	Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.
Materials and Supplies	'
	Materials and Supplies
	Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when installed, as appropriate.
Property and Plant	'
	Property, Plant and Equipment
	The cost of additions to and betterments of units of property, plant and equipment are capitalized. The cost includes labor, material, applicable taxes, and overhead. Interest incurred during construction is capitalized as a cost of assets. Expenditures for major installations, replacements and improvements or betterments are capitalized and depreciated over the expected life cycle. Expenditures for maintenance, repairs and minor renewals to maintain the operating condition of our assets are expensed. When units of depreciable property are retired, the original costs, less salvage values, are charged to accumulated depreciation. Asset removal costs incurred that do not constitute legal obligations are generally expensed as incurred. Please read Asset Retirement Obligations below and Note 3—Property, Plant and Equipment, for further discussion.
	Depreciation
	Depreciation is provided using the straight-line method over the estimated service lives of the assets, ranging from 1 to 36 years. Our provision for depreciation in 2013, 2012 and 2011 has an average depreciable cost of approximately 3%.
Goodwill and Intangible Assets	'
	Intangible Assets
	We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.
	At December 31, 2013 and 2012, intangible assets consisted of emission allowances. The book value of emission allowances was less than $1 million at the end of both years. Emission allowances are charged to fuel expense as they are used in operations.
Impairment of Long-lived Assets	'
	Impairment of Long-lived Assets
	We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which we determine an asset meets held for sale criteria, we record an impairment charge to the extent the carrying value exceeds its fair value less cost to sell. Please read Note 11—Impairment and Other Charges for further discussion.
Environment Costs	'
	Environmental Costs
	Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.
Unamortized Debt Discount, Premium, and Expense	'
	Unamortized Debt Discount, Premium and Expense
	Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues.
Operating Revenue	'
	Operating Revenue
	Revenue is earned from the facilities based on generation for the sale of energy and the sale of capacity. Operating revenue for electric service is recorded based on net generation in accordance with our PSA with IPM. Revenue is recognized when the product or service is delivered to a customer, unless they meet the definition of a derivative.
Income Taxes	'
	Income Taxes
	Upon the AER Acquisition, we were acquired in a transaction that resulted in an “ownership change,” as defined under IRC Section 382. Prior to the AER Acquisition, we were included in the consolidated federal and state income tax returns of Ameren Corporation. Genco and Ameren Corporation were parties to a tax sharing agreement that provided that the amount of tax recognized is similar to that which would have been owed had we been separately subject to tax.
	Upon the closing of the AER Acquisition, we are included in the consolidated federal and state returns of Dynegy. Genco and Dynegy have entered into a new tax sharing agreement. Under the terms of the new tax sharing agreement, we recognize taxes based on a separate company income tax return basis, as defined in the agreement. Under IRC Section 382, we are subject to a limitation in the amount of NOLs that could be used in any one year following this ownership change. Further, we are subject to a worthless stock loss deduction equal to Ameren’s tax basis in our stock prior to the AER Acquisition. Accordingly, we determined that our pre-acquisition NOLs are unlikely to be used against future taxable income and the estimated benefits therefrom have been written down to zero. We have also recorded the effects of a reduction of other tax attributes, totaling $433 million. These adjustments to our NOLs and tax attributes resulted in a charge to paid-in capital at the Acquisition Date of $178 million and a reduction to our income tax benefit for 2013 in the amount of $39 million. Please read Note 7—Income Taxes for further discussion.
	We use an asset and liability approach for our financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.
Noncontrolling Interest	'
	Noncontrolling Interest
	Noncontrolling interest is comprised of the 20% of EEI we do not own. This noncontrolling interest is classified as a component of equity separate from our equity in the consolidated balance sheet.
Accounting Changes and Other Matters	'
	Accounting Changes and Other Matters
	The following is a summary of recently adopted authoritative accounting guidance as well as guidance issued but not yet adopted that could impact us.
	Accounting Standards Adopted
	Disclosures about Fair Value Measurements. In May 2011, FASB issued additional authoritative guidance regarding fair value measurements. The guidance amended the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments did not affect our results of operations, financial position, or liquidity, as this guidance only requires additional disclosures. We adopted this guidance for the first quarter 2012. Please read Note 9—Fair Value Measurements for further discussion.
	Presentation of Comprehensive Income. In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in separate but consecutive statements. This guidance was effective for us beginning in the first quarter 2012 with retroactive application required. The implementation of the amended guidance did not affect results of operations, financial position, or liquidity. In February 2013, the FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. The amendments did not affect our results of operations, financial position, or liquidity, as this guidance only requires additional disclosures and substantially all the information that this amended guidance requires is already disclosed elsewhere in the financial statements. This guidance was effective for us beginning in the first quarter 2013 on a prospective basis.
	Disclosures about Offsetting Assets and Liabilities. In December 2011, FASB issued additional authoritative guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The amendments did not affect our results of operations, financial positions or liquidity, as this guidance only requires additional disclosures. This guidance was effective for us beginning in the first quarter 2013 with retrospective application required.
New Accounting Pronouncements Not yet Adopted	'
	Accounting Standards Not Yet Adopted
	Presentation of Unrecognized Tax Benefits. In July 2013, the FASB issued ASU 2013-11-Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.  The provisions of the rule require an unrecognized tax benefit to be presented as a reduction to a deferred tax asset in the financial statements for an NOL carryforward, a similar tax loss, or a tax credit carryforward except in circumstances when the carryforward or tax loss is not available at the reporting date under the tax laws of the applicable jurisdiction to settle any additional income taxes or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes.  When those circumstances exist, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets.  The new financial statement presentation provisions relating to this update are prospective and effective for interim and annual periods beginning after December 15, 2013, with early adoption permitted.  We are currently assessing the future impact of this update, but we do not anticipate a material impact on our financial condition, results of operations or cash flows.
Asset Retirement Obligations	'
	Asset Retirement Obligations
	Authoritative accounting guidance requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments to AROs based on changes in the estimated fair values of the obligations. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing, or amount of cash flows associated with AROs affect our estimates of fair value. We have recorded AROs for retirement costs associated with asbestos removal, river structures and CCR storage facilities.
Employee Separation and Other Charges	'
	Employee Separation and Other Charges
	In each of the past three years, employee separation programs were initiated to reduce positions under the terms and benefits consistent with our former parent Ameren’s standard management separation program. We recorded pretax charges related to these programs of $3 million, $1 million and $4 million in 2013, 2012 and 2011, respectively. The 2013 and 2012 charges were recorded in “Other operations and maintenance” expense on the consolidated statements of operations. The 2011 charge related to the closure of the Meredosia and Hutsonville facilities and was recorded in “Impairment and other charges” on the consolidated statement of operations. Please read Note 11—Impairment and Other Charges for further discussion. In 2014, we expect to payout approximately $3 million of severance benefits to affected employees.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Schedule of Materials and Supplies	'
	The following table presents a breakdown of materials and supplies at December 31, 2013 and 2012:
			Year Ended December 31,
	(amounts in millions)		2013			2012
	Fuel (a)		$	45		$	48
	Other materials and supplies		33			37
	Total		$	78		$	85
	__________________________________________
	(a)	Consists of coal for 2013 and coal and natural gas for 2012.
Property, Plant and Equipment	'
	The estimated economic service lives of our asset groups are as follows:
	Asset Group		Range of
			Years
	Power generation facilities		1 to 30
	Environmental upgrades		10 to 30
	Buildings and improvements		7 to 36
	Office and other equipment		2 to 15
	A summary of our property, plant and equipment is as follows:
	(amounts in millions)		31-Dec-13			31-Dec-12
	Property, plant and equipment		$	2,551		$	2,787
	Less: Accumulated depreciation and amortization		(1,027		)	(1,192		)
			1,524			1,595
	Construction work in progress		349			292
	Property, plant and equipment, net		$	1,873		$	1,887
Schedule of Asset Retirement Obligations	'
	The following table provides a reconciliation of the beginning and ending carrying amounts of AROs for the years ended December 31, 2012 and 2013:
	(amounts in millions)
	Balance at December 31, 2011		$	61
	Liabilities incurred		2
	Liabilities settled		(5		)
	Accretion in 2012		4
	Change in estimates		(3		)
	Balance at December 31, 2012		59
	Liabilities incurred		3
	Liabilities settled (a)		(28		)
	Accretion in 2013		4
	Change in estimates		5
	Balance at December 31, 2013		$	43
	__________________________________________
	(a)	Under the terms of the agreement entered into on March 14, 2013 to divest New AER to IPH, Ameren retained the existing AROs associated with the closure of the Meredosia and Hutsonville facilities, which were estimated at $28 million as of the date of divestiture, December 2, 2013.
Assets Held-for-sale	'
	The following table presents the components of assets and liabilities held for sale on our consolidated balance sheet at December 31, 2012:
	(amounts in millions)		31-Dec-12
	Assets held for sale
	Materials and supplies		$	12
	Mark-to-market derivative assets		4
	Property, plant and equipment, net		348
	Total assets held for sale		$	364
	Liabilities held for sale
	Accounts and wages payable		$	9
	Taxes accrued		3
	Mark-to-market derivative liabilities		3
	Asset retirement obligations		10
	Total liabilities held for sale		$	25

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Schedule of Physical Gigawatthour Sales and Purchases under Related Party Electric PSAs	'
	The following table presents the amount of physical power sales and purchases under our related party electric PSAs with IPM, including EEI’s PSA with IPM, in gigawatthours:
			Year Ended December 31,
			2013		2012	2011
	Genco sales to IPM		12,111		11,933	14,293
	EEI sales to IPM		6,856		6,421	7,633
	EEI purchases from IPM		29		22	886
Schedule of Related Party Transactions	'
	The following table presents the impact of related party transactions. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4—Short-Term Debt and Liquidity.
				Year Ended December 31,
	(amounts in millions)		Income Statement Line Item	2013		2012		2011
	Genco and EEI power supply agreements with IPM		Operating Revenues	$	709	$	804	$	1,006
	Natural gas sales to Medina Valley (a)		Operating Revenues	—		1		3
	Services provided to AER affiliates		Operating Revenues	6		—		—
	Total Operating Revenues			$	715	$	805	$	1,009
	Ameren Missouri gas transportation agreement		Fuel	$	1	$	1	$	1
	EEI power supply agreement with IPM		Purchased Power	$	66	$	1	$	36
	Support services agreement		Other Operations and Maintenance	$	13	$	21	$	19
	Money pool borrowings (advances)		Interest (Charges) Income	(b)		(b)		(b)
	__________________________________________
	(a)	Natural gas sold at fair value.
	(b)	Amount less than $1 million.

Property_and_Plant_Net_Tables

Property and Plant, Net (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment	'
	The estimated economic service lives of our asset groups are as follows:
	Asset Group	Range of
		Years
	Power generation facilities	1 to 30
	Environmental upgrades	10 to 30
	Buildings and improvements	7 to 36
	Office and other equipment	2 to 15
	A summary of our property, plant and equipment is as follows:
	(amounts in millions)	31-Dec-13			31-Dec-12
	Property, plant and equipment	$	2,551		$	2,787
	Less: Accumulated depreciation and amortization	(1,027		)	(1,192		)
		1,524			1,595
	Construction work in progress	349			292
	Property, plant and equipment, net	$	1,873		$	1,887

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Long-term Debt, Unclassified [Abstract]	'
Schedule of Long-term Debt Outstanding	'
	The following table presents our long-term debt outstanding:
	(amounts in millions)		31-Dec-13			31-Dec-12
	Unsecured notes:
	Senior notes Series F 7.95% due 2032		$	275		$	275
	Senior notes Series H 7.00% due 2018		300			300
	Senior notes Series I 6.30% due 2020		250			250
	Total long-term debt, gross		825			825
	Less: Unamortized discount		(1		)	(1		)
	Less: Maturities due within one year		—			—
	Long-term debt, net		$	824		$	824
Schedule of Required and Actual Debt Ratios	'
	The following table summarizes these required ratios:
			Required Ratio
	Restricted payment interest coverage ratio (a)		≥1.75
	Additional indebtedness interest coverage ratio (b)		≥2.50
	Additional indebtedness debt-to-capital ratio (b)		≤60%
	_______________________________________
	(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.
	(b)	Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Retirement_Benefits_Tables

Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Funded status of pension and postretirement benefit plans	'
	The following table presents the funded status of our pension and postretirement benefit plans as of December 31, 2013 and 2012. It also provides the amounts included in accumulated OCI at December 31, 2013 and 2012 that have not been recognized in net periodic benefit costs. These amounts include the funded status of EEI’s pension and postretirement plans as well as an allocation of our share of obligation and plan assets associated with our participation in Ameren’s and Dynegy’s single-employer pension and postretirement plans.
			2013								2012
	(amounts in millions)		Pension Benefits				Postretirement				Pension Benefits			Postretirement
							Benefits							Benefits
	Accumulated benefit obligation at end of year		$	89			N/A				$	251		N/A
	Change in benefit obligation:
	Net benefit obligation at beginning of year		$	251			$	93			$	239		$	150
	Transfer of liability from (to) Ameren Services / Medina Valley (a)		(7		)		(2		)		13			2
	Transfer of liability to Ameren (b)		(136		)		(33		)		—			—
	Allocation of liability from Dynegy (c)		—				4				—			—
	Service cost		5				2				5			3
	Interest cost		10				3				10			6
	Plan amendments (d)(e)		—				(4		)		(6		)	(75		)
	Participant contributions		—				1				—			1
	Actuarial (gain) loss		(11		)		(8		)		3			15
	Curtailments (f)		—				1				2			(1		)
	Benefits paid		(22		)		(7		)		(15		)	(8		)
	Administrative expenses paid		(1		)		—				—			—
	Net benefit obligation at end of year		89				50				251			93
	Change in plan assets:
	Fair value of plan assets at beginning of year		183				83				167			81
	Transfer of assets from Ameren Services / Medina Valley (a)		(6		)		(1		)		9			2
	Transfer of assets to Ameren (b)		(130		)		(21		)		—			—
	Actual return on plan assets		36				12				11			7
	Employer contributions		15				—				11			—
	Participant contributions		—				1				—			1
	Benefits paid		(22		)		(7		)		(15		)	(8		)
	Administrative expenses paid		(1		)		—				—			—
	Fair value of plan assets at end of year		75				67				183			83
	Funded status		$	14			$	(17	)		$	68		$	10
	Amounts recognized in the balance sheet consist of:
	Noncurrent asset (g)		$	—			$	(21	)		$	—		$	(14	)
	Current liability		—				—				—			—
	Noncurrent liability		14				4				68			24
	Net liability (asset) recognized		$	14			$	(17	)		$	68		$	10
	Amounts (pretax) recognized in accumulated OCI consist of:
	Net actuarial loss		$	17			$	44			$	73		$	59
	Prior service cost (credit)		(3		)		(43		)		(10		)	(62		)
	Total		$	14			$	1			$	63		$	(3	)
	_________________________________________
	(a)	In October 2013, 52 employees from Genco were transferred to Ameren Services and Medina Valley through an internal reorganization. On December 31, 2012, 74 employees from Ameren Services were transferred to Genco through an internal reorganization.
	(b)	Effective with the AER Acquisition, Ameren retained the portion of Genco’s pension obligations associated with the current and former employees of Genco and the portion of Genco’s postretirement benefit obligations associated with the employees of Genco who were eligible to retire at December 2, 2013 with respect to such employees’ participation in Ameren’s single-employer pension and postretirement plans.
	(c)	Amount represents the allocation of the obligation from our participation in Dynegy’s single-employer plans.
	(d)	Effective with the AER Acquisition, the EEI management postretirement plan was remeasured as a result of a reduction in employees participating in the postretirement plan. This remeasurement reduced the benefit obligation, resulting in the establishment of a prior service credit.
	(e)	In 2012, EEI's pension plan was amended to adjust the calculation of the future benefit obligation for all of its active management employees and certain union-represented employees from a traditional, final pay formula to a cash balance formula. Additionally, in 2012, EEI's management and union-represented postretirement medical benefit plans were amended to adjust for moving to a Medicare Advantage plan.
	(f)	Effective with the AER Acquisition, there was a reduction in employees who participated in the EEI management postretirement plan which resulted in a curtailment of the plan. EEI implemented an employee reduction program in 2012, which resulted in a curtailment of its pension and management postretirement benefit plans.
	(g)	The EEI union postretirement plan was over-funded as of December 31, 2013 and 2012 and the EEI management postretirement plan was over-funded as of December 31, 2013, which was included in our balance sheets in “Other assets.”
Assumptions Used To Determine Net Periodic Benefit Cost	'
	The following table presents the assumptions used to determine our benefit obligations at December 31, 2013 and 2012:
			Pension Benefits						Postretirement Benefits
			2013			2012			2013			2012
	Discount rate at measurement date (a)		4.82	%		4	%		4.78	%		4	%
	Increase in future compensation (a)		3.5	%		4.48	%		3.5	%		4.41	%
	Ameren - Medical cost trend rate (initial)		N/A			N/A			N/A			5	%
	Ameren - Medical cost trend rate (ultimate)		N/A			N/A			N/A			5	%
	Ameren - Years to ultimate rate		N/A			N/A			N/A			0
	EEI - Medical cost trend rate (initial)		N/A			N/A			7.75	%		7.96	%
	EEI - Medical cost trend rate (ultimate)		N/A			N/A			4.5	%		4.5	%
	EEI - Years to ultimate rate		N/A			N/A			10 years			15 years
	_________________________________________
	(a)	A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans at December 31, 2013. A weighted average rate of EEI’s and Ameren’s pension and postretirement plans at December 31, 2012.
	The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2013, 2012 and 2011:
			Pension Benefits									Postretirement Benefits
			2013			2012			2011			2013		2012			2011
	Discount rate (a)		(b)			4.36	%		5.33	%		(c)		4.29	%		5.39	%
	Expected return on plan assets (a)		7.65	%		7.84	%		8	%		7.59	%	7.87	%		7.93	%
	Increase in future compensation (a)		(d)			3.7	%		3.7	%		(e)		3.86	%		3.83	%
	Ameren - Medical cost trend rate (initial)		N/A			N/A			N/A			5	%	5.5	%		6	%
	Ameren - Medical cost trend rate (ultimate)		N/A			N/A			N/A			5	%	5	%		5	%
	Ameren - Years to ultimate rate		N/A			N/A			N/A			0		1 year			2 years
	EEI - Medical cost trend rate (initial)		N/A			N/A			N/A			(f)		8.3	%		8.65	%
	EEI - Medical cost trend rate (ultimate)		N/A			N/A			N/A			4.5	%	4.5	%		4.5	%
	EEI - Years to ultimate rate		N/A			N/A			N/A			(g)		15 years			16 years
	_________________________________________
	(a)	A weighted average rate of EEI’s and Ameren’s pension and postretirement plans.
	(b)	The discount rate used for EEI’s pension plan was 4.00% and 4.67% for the period from January 1, 2013 through December 1, 2013 and the period from December 2, 2013 through December 31, 2013, respectively. The discount rate used for Ameren’s pension plans was 4.00% for the period from January 1, 2013 through December 1, 2013.
	(c)	The discount rate used for EEI’s postretirement plans was 4.00% for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 4.00% for EEI union employees and 4.75% for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively. The discount rate used for Ameren’s postretirement plans was 4.00% for the period from January 1, 2013 through December 1, 2013.
	(d)	The average rate of compensation increase used for EEI’s pension plan was 5.97% and 3.50% for the period from January 1, 2013 through December 1, 2013 and the period from December 2, 2013 through December 31, 2013, respectively. The average rate of compensation increase used for Ameren’s pension plans was 3.50% for the period from January 1, 2013 through December 1, 2013.
	(e)	The average rate of compensation increase used for EEI’s postretirement plans was 6.35% for EEI union employees and 3.81% for EEI management employees for the period from January 1, 2013 through December 1, 2013 and 6.35% for EEI union employees and 3.50% for EEI management employees and the period from December 2, 2013 through December 31, 2013, respectively. The average rate of compensation increase used for Ameren’s postretirement plans was 3.50% for the period from January 1, 2013 through December 1, 2013.
	(f)	The initial medical cost trend rate used for EEI’s postretirement plans was 7.96% for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 7.96% for EEI union employees and 7.75% for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively.
	(g)	The years to ultimate trend rate used for EEI’s postretirement plans was 14 years for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 14 years for EEI union employees and 10 years for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively.
Cash contributions made to benefit plans	'
	The following table presents the cash contributions made to our defined benefit retirement plans during 2013, 2012 and 2011:
			Pension Benefits
	(amounts in millions)		2013				2012				2011
	Ameren allocation (a)		$	5			$	4			$	4
	EEI		10				7				8
	Total		$	15			$	11			$	12
	_________________________________________
	(a)	Represents an allocation of our share of cash contributions associated with our participation in Ameren’s pension plans.
EEI's allocation of plan assets	'
	The following table presents EEI’s target allocations for 2014 and EEI’s pension and postretirement plans’ asset categories as of December 31, 2013 and 2012.
	Asset Category		Target Allocation			Percentage of Plan Assets at December  31,
			2014			2013			2012
	Pension Plan:
	Equity securities		60	%		61	%		59	%
	Debt securities		40	%		39	%		38	%
	Cash		—	%		—	%		3	%
	Total		100	%		100	%		100	%
	Postretirement Plans:
	Equity securities		60	%		60	%		62	%
	Debt securities		40	%		38	%		36	%
	Cash		—	%		2	%		2	%
	Total		100	%		100	%		100	%
EEI pension plan assets measured at fair value	'
	The following table sets forth, by level within the fair value hierarchy discussed in Note 9—Fair Value Measurements, the EEI pension plan assets measured at fair value as of December 31, 2013:
	(amounts in millions)		Quoted Prices in				Significant Other				Significant Other			Total
			Active Markets for				Observable Inputs				Unobservable
			Identified Assets				(Level 2)				Inputs
			(Level 1)								(Level 3)
	Cash and cash equivalents		$	—			$	—			$	—		$	—
	Equity securities:
	U.S. large capitalization		—				26				—			26
	U.S. small capitalization		—				14				—			14
	International		—				6				—			6
	Debt Securities		—				29				—			29
	Total		$	—			$	75			$	—		$	75
	As described above, a portion of Ameren’s pension plan assets was allocated to us as of December 31, 2012. The amount of Ameren pension plan assets allocated to us for financial reporting purposes as of December 31, 2012, was $117 million based on pensionable salaries. The following table sets forth, by level within the fair value hierarchy discussed in Note 9—Fair Value Measurements, the EEI pension plan assets measured at fair value as of December 31, 2012:
	(amounts in millions)		Quoted Prices in				Significant Other				Significant Other			Total
			Active Markets for				Observable Inputs				Unobservable
			Identified Assets				(Level 2)				Inputs
			(Level 1)								(Level 3)
	Cash and cash equivalents		$	—			$	2			$	—		$	2
	Equity securities:
	U.S. large capitalization		—				22				—			22
	U.S. small capitalization		—				12				—			12
	International		—				5				—			5
	Debt securities		—				25				—			25
	Total		$	—			$	66			$	—		$	66
	As described above, a portion of Dynegy’s postretirement plan assets is allocated to us as of December 31, 2013. The amount of Dynegy postretirement plan assets allocated to us for financial reporting purposes as of December 31, 2013 was $1 million based on the number of our non-EEI employees. The following table sets forth, by level within the fair value hierarchy discussed in Note 9—Fair Value Measurements, the EEI postretirement benefit plans assets measured at fair value as of December 31, 2013:
	(amounts in millions)		Quoted Prices in				Significant Other				Significant Other			Total
			Active Markets for				Observable Inputs				Unobservable
			Identified Assets				(Level 2)				Inputs
			(Level 1)								(Level 3)
	Cash and cash equivalents		$	1			$	—			$	—		$	1
	Equity securities:
	U.S. large capitalization		33				—				—			33
	International		8				—				—			8
	Debt securities:
	U.S. treasury and agency securities		13				1				—			14
	Municipal bonds		—				5				—			5
	Corporate bonds		—				6				—			6
	Total		$	55			$	12			$	—		$	67
	As described above, a portion of Ameren’s postretirement plan assets was allocated to us as of December 31, 2012. The amount of Ameren postretirement plan assets allocated to us for financial reporting purposes as of December 31, 2012 was $21 million based on the number of our non-EEI employees. The following table sets forth, by level within the fair value hierarchy discussed in Note 9—Fair Value Measurements, the EEI postretirement benefit plans assets measured at fair value as of December 31, 2012:
	(amounts in millions)		Quoted Prices in				Significant Other				Significant Other			Total
			Active Markets for				Observable Inputs				Unobservable
			Identified Assets				(Level 2)				Inputs
			(Level 1)								(Level 3)
	Cash and cash equivalents		$	—			$	1			$	—		$	1
	Equity securities:
	U.S. large capitalization		32				—				—			32
	International		7				—				—			7
	Debt securities:
	U.S. treasury and agency securities		—				11				—			11
	Municipal bonds		—				5				—			5
	Corporate bonds		—				6				—			6
	Total		$	39			$	23			$	—		$	62
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 and Dynegy’s pension and postretirement benefit plans during 2013, 2012 and 2011:
	(amounts in millions)		Pension Benefits				Postretirement Benefits
	2013
	Service cost		$	5			$	2
	Interest cost		10				3
	Expected return on plan assets		(13		)		(5		)
	Amortization of:
	Prior service cost		(1		)		(8		)
	Actuarial loss		6				5
	Settlements		1				—
	Curtailment gain (a)		—				(26		)
	Net periodic benefit cost		$	8			$	(29	)
	2012
	Service cost		$	5			$	3
	Interest cost		10				6
	Expected return on plan assets		(13		)		(6		)
	Amortization of:
	Prior service cost		(1		)		(3		)
	Actuarial loss		6				4
	Curtailment loss (b)		2				—
	Net periodic benefit cost		$	9			$	4
	2011
	Service cost		$	6			$	3
	Interest cost		11				6
	Expected return on plan assets		(13		)		(6		)
	Amortization of:
	Prior service cost		—				(3		)
	Actuarial loss		3				2
	Net periodic benefit cost		$	7			$	2
	_________________________________________
	(a)	Represents EEI’s management postretirement benefit plans’ curtailment gain recognized due to a reduction of employees as a result of the AER Acquisition.
	(b)	Represents EEI’s pension and management postretirement benefit plans’ curtailment loss recognized as a result of its 2012 employee reduction program.
Schedule of amounts in AOCI to be recognized in 2013	'
	The estimated amounts that will be amortized from accumulated OCI into net periodic benefit cost in 2014 are as follows:
	(amounts in millions)		Pension Benefits (a)				Postretirement Benefits (a)
	Prior service cost (credit)		$	—			$	(4	)
	Net actuarial loss		1				3
	Total		$	1			$	(1	)
	_________________________________________
	(a)	Includes only amounts for EEI’s plans.
Expected pension and postretirement benefit payments	'
	The expected pension and postretirement benefit payments for expected future service, as of December 31, 2013, are as follows:
	(amounts in millions)		Pension Benefits (a)				Postretirement Benefits (a)
	2014		$	14			$	3
	2015		$	6			$	3
	2016		$	7			$	3
	2017		$	7			$	3
	2018		$	7			$	3
	2019 - 2023		$	32			$	14
	_________________________________________
	(a)	Includes only amounts for EEI’s plans.
Sensitivity to potential changes in key assumptions	'
	The table below reflects the sensitivity to potential changes in key assumptions:
			Pension Benefits (a)				Postretirement Benefits (a)
	(amounts in millions)		Service Cost		Projected		Service Cost				Postretirement
			and Interest		Benefit		and Interest				Benefit
			Cost		Obligation		Cost				Obligation
	1.00% increase in annual medical trend		N/A		N/A		$	1			$	5
	1.00% decrease in annual medical trend		N/A		N/A		$	—			$	(4	)
	_________________________________________
	(a)	Includes amounts for EEI’s plans and our participation in Dynegy’s plans.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule Of Effective Income Tax Rate Reconciliation	'
	The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate:
			Year Ended December 31,
	(amounts in millions)		2013			2012			2011
	Statutory federal income tax rate:		35	%		35	%		35	%
	Increases (decreases) from:
	Tax credits		—			(2	)		(1	)
	Amortization of investment tax credit		—			—			(1	)
	State tax		6			7			6
	Production activities deduction		—			—			3
	Reserve for uncertain tax positions		—			2			—
	Acquisition adjustment (a)		(15	)		—			—
	Effective income tax rate		26	%		42	%		42	%
	_________________________________________
	(a)	Acquisition adjustment is primarily the result of the loss of expected benefits from the NOL carryforward in existence at the Acquisition Date due to IRC Section 382 limits.
Schedule Of Components Of Income Tax Expense (Benefit)	'
	The following table presents the components of income tax expense (benefit):
			Year Ended December 31,
	(amounts in millions)		2013				2012				2011
	Current taxes:
	Federal		$	(50	)		$	(15	)		$	(21	)
	State		(14		)		(5		)		(7		)
	Deferred taxes:
	Federal		6				(6		)		43
	State		(6		)		(2		)		18
	Deferred investment tax credits, amortization		(1		)		(1		)		(1		)
	Total income tax expense (benefit)		$	(65	)		$	(29	)		$	32
Schedule Of Deferred Tax Assets And Liabilities Resulting From Temporary Differences	'
	The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences:
			December 31,
	(amounts in millions)		2013				2012
	Accumulated deferred income taxes, net liability (asset):
	Plant related		$	541			$	424
	Deferred employee benefit costs		(24		)		(37		)
	ARO		(16		)		(28		)
	Other (a)		38				(36		)
	Total net accumulated deferred income tax liabilities (b)		$	539			$	323
	_________________________________________
	(a)	Included deferred tax assets related to net operating loss and tax credit carryforwards as of December 31, 2012.
	(b)	Includes $11 million in “Other current assets” on the balance sheet as of December 31, 2012.
Schedule Of Changes To Unrecognized Tax Benefits And Related Interest	'
	Uncertain Tax Positions
	A reconciliation of the change in the unrecognized tax benefit balance is as follows:
			Year Ended December 31,
	(amounts in millions)		2013				2012				2011
	Unrecognized tax benefits - beginning of year		$	6			$	9			$	20
	Increases based on tax positions prior to current year		2				1				1
	Decreases based on tax positions prior to current year		(3		)		(2		)		(12		)
	Increases based on tax positions related to current year		—				—				1
	Decreases based on tax positions related to current year		(1		)		(1		)		—
	Adjustment of balance due to change in ownership		(3		)		—				—
	Decreases related to the lapse of statute of limitations		(1		)		(1		)		(1		)
	Unrecognized tax benefits - end of year		$	—			$	6			$	9
	Total unrecognized tax benefits (detriments) that, if recognized, would affect the effective tax rates		$	—			$	—			$	1
Reconciliation Of Changes In Liability For Interest On Unrecognized Tax Benefits	'
	A reconciliation of the change in the liability for interest on unrecognized tax benefits is as follows:
			Year Ended December 31,
	(amounts in millions)		2013				2012				2011
	Liability for interest - beginning of year		$	1			$	1			$	2
	Interest charges (income)		—				—				(1		)
	Adjustment of balance due to change in ownership		(1		)		—				—
	Liability for interest - end of year		$	—			$	1			$	1

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instrument Detail [Abstract]

'

Open Gross Derivative Volumes By Commodity Type

'

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

Quantity (in millions)

Commodity

2013

2012

Coal (in tons)

—

5

Fuel oils (in gallons) (a)

—

40

Natural gas (in mmbtu) (b)

—

42

Power (in MWh)

—

—

________________________________________

(a)

Fuel oils consist of heating and crude oil.

(b)

Amounts include commodity contracts classified as held for sale.

Derivative Instruments Carrying Value

'

The following table presents the carrying value of all derivative instruments as reported in our balance sheets as of December 31, 2012:

(amounts in millions)

Year Ended December 31, 2012

Derivative assets not designated as hedging instruments

Commodity contracts:

Coal

Other assets

$

1

Fuel oils

Other current assets

2

Other assets

1

Natural gas

Other current assets

4

Total assets

$

8

Derivative liabilities not designated as hedging instruments

Commodity contracts:

Coal

Other current liabilities

$

7

Other deferred credits and liabilities

3

Fuel oils

Other current liabilities

1

Other deferred credits and liabilities

1

Natural gas

Liabilities held for sale

3

Total liabilities

$

15

Maximum Exposure If Counterparties Fail To Perform On Contracts

'

The following table presents the maximum exposure, as of 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.

(amounts in millions)

Coal

Commodity

Electric

Financial

Oil and Gas

Total

Producers

Marketing

Utilities

Companies

Companies

Companies

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 and collateral held as of December 31, 2012:

(amounts in millions)

Coal

Commodity

Electric

Financial

Oil and Gas

Total

Producers

Marketing

Utilities

Companies

Companies

Companies

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 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 December 31, 2013, and (2) those counterparties with rights to do so requested collateral:

(amounts in millions)

Aggregate Fair Value of

Cash

Potential Aggregate Amount of

Derivative Liabilities (a)

Collateral Posted

Additional Collateral Required

2012 (b)

$

48

$

—

$

31

__________________________________________

(a)

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

Cash Flow Hedges

'

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

(amounts in millions)

Gain (Loss)

Location of (Gain) Loss

(Gain) Loss

Location of Gain (Loss)

Gain (Loss)

Recognized in OCI (a)

Reclassified from

Reclassified from

Recognized in Income (c)

Recognized

Accumulated OCI into

Accumulated OCI

in Income (c)

Income (b)

into Income (b)

2013

Interest rate (d)

$

—

Interest Charges

$

1

Interest Charges

$

—

2012

Interest rate (d)

$

—

Interest Charges

$

1

Interest Charges

$

—

__________________________________________

(a)

Effective portion of gain (loss).

(b)

Effective portion of (gain) loss on settlements.

(c)

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

(d)

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

Other Derivatives

'

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

Location of Gain (Loss)

Gain (Loss) Recognized

Recognized in Income

in Income

(amounts in millions)

2013

2012

Coal

Operating Expenses - Fuel

$

9

$

(9

)

Fuel oils

Operating Expenses - Fuel

(1

)

(9

)

Natural gas (generation) (a)

Operating Expenses - Fuel

(1

)

—

Power

Operating Revenues

—

—

Total

$

7

$

(18

)

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis	'
	The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012:
				Quoted Prices in			Significant Other			Significant Other			Total
				Active Markets for			Observable			Unobservable
				Identical Assets			Inputs			Inputs
				or Liabilities			(Level 2)			(Level 3)
				(Level 1)
	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.
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:
			Year Ended December 31,
	(amounts in millions)		2013			2012
	Fuel oils:
	Beginning balance at January 1		$	1		$	1
	Realized and unrealized gains (losses):
	Included in earnings		—			—
	Total realized and unrealized gains (losses)		—			—
	Purchases		—			—
	Settlements		(1		)	—
	Transfers into Level 3		—			1
	Transfers out of Level 3		—			(1		)
	Ending balance at December 31		$	—		$	1
	Change in unrealized gains (losses) related to assets/liabilities held at December 31		$	—		$	—
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:
			December 31, 2013						December 31, 2012
	(amounts in millions)		Carrying Amount			Fair Value			Carrying Amount			Fair Value
	Long-term debt (including current portion)		$	824		$	683		$	824		$	618

Impairment_and_Other_Charges_T

Impairment and Other Charges (Tables)	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
Impairment Charges	'
	The following table summarizes the pretax charges recognized for the years ended December 31, 2013, 2012 and 2011:
	(amounts in millions)	Long-Lived		Emission		Total
		Assets and Related Charges		Allowances
	2013	$	199	$	—	$	199
	2012	$	70	$	—	$	70
	2011	$	34	$	1	$	35

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Schedule of Accumulated Other Comprehensive Income (Loss)	'
	Changes in accumulated other comprehensive income (loss), net of tax, by component are as follows:
	(amounts in millions)		Year Ended December 31, 2013			Year Ended December 31, 2012
	Beginning of period		$	(40	)	$	(72	)
	Current period other comprehensive income:
	Actuarial gain and plan amendments (net of tax expense of $8 and $20, respectively)		12			28
	Amounts reclassified from accumulated other comprehensive income (loss):
	Reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges, net (net of tax benefit of zero and zero, respectively) (a)		1			1
	Amortization of unrecognized prior service cost and actuarial gain (loss) (net of tax expense of $1 and $2, respectively) (b)		1			3
	Amounts reclassified from accumulated other comprehensive income (loss) (net of tax benefit of $9 and zero, respectively) (c)		(13		)	—
	Total amounts reclassified from accumulated other comprehensive income (loss)		(11		)	4
	Net current period other comprehensive income (loss), net of tax		1			32
	AER Acquisition (net of tax expense of $20 and zero, respectively) (d)		28			—
	End of period		$	(11	)	$	(40	)
	__________________________________________
	(a)	Amount related to the reclassification of mark-to-market loss on cash flow hedging activities, net and was recorded in Interest Charges in our consolidated statements of operations.
	(b)	Amounts are associated with our defined benefit pension and other postretirement benefit plans and are included in the computation of net periodic pension cost. Please read Note 6—Retirement Benefits for further discussion.
	(c)	Amount related to the EEI curtailment gain on pension and postretirement benefit plans and was recorded in Other operations and maintenance in our consolidated statements of operations. Please read Note 6—Retirement Benefits for further discussion.
	(d)	Amount related to the transfer of certain defined benefit pension and other postretirement benefit plans as a part of the AER Acquisition. Please read Note 6—Retirement Benefits for further discussion.

Selected_Quarterly_Information1

Selected Quarterly Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Selected Quarterly Financial Information [Abstract]	'
Summary Of Selected Quarterly Information	'
	Quarter Ended		Operating		Operating Income (Loss) (a)			Net Income (Loss)			Net Income (Loss)
			Revenues								Attributable to
											Illinois Power
											Generating Company
	March 31, 2013		$	187	$	(204	)	$	(129	)	$	(129	)
	March 31, 2012		$	194	$	13		$	(3	)	$	(1	)
	June 30, 2013		$	187	$	(25	)	$	(22	)	$	(22	)
	June 30, 2012		$	194	$	(4	)	$	(6	)	$	(4	)
	September 30, 2013		$	275	$	—		$	(5	)	$	(5	)
	September 30, 2012		$	218	$	34		$	11		$	13
	December 31, 2013		$	155	$	16		$	(33	)	$	(32	)
	December 31, 2012		$	202	$	(60	)	$	(42	)	$	(41	)
	_________________________________________
	(a)	Includes pretax “Impairment and other charges” of $199 million and $70 million recorded during the years ended December 31, 2013 and 2012, respectively. Please read Note 11—Impairment and Other Charges for further discussion.

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Mar. 14, 2013

Jun. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2011

Mar. 14, 2013

Oct. 11, 2013

Put Option [Member]

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

Columbia CT Energy Center [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Emission Allowances [Member]

Emission Allowances [Member]

Emission Allowances [Member]

EEI [Member]

Employee Severance [Member]

Other Asset Sales [Member]

Initial Payment Received [Member]

Additional Payment Received [Member]

Subsequent Event [Member]

Significant Other Unobservable Inputs (Level 3) [Member]

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

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

Put Option [Member]

Put Option [Member]

Put Option [Member]

Accounting Policies [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Method Investment, Ownership Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

80.00%

'

'

'

'

Capital contributions from parent

'

$72

$0

$0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt, gross

825

825

825

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percent of average depreciable cost

'

'

'

'

'

'

'

3.00%

3.00%

3.00%

'

'

'

'

'

'

'

'

Book value of emission allowances (less than $1 million)

'

'

'

'

'

'

'

'

'

'

1

1

'

'

'

'

'

'

Amortization of intangible assets

'

'

'

'

'

'

'

'

'

'

1

1

2

'

'

'

'

'

Operating Loss Carryforwards

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Income Tax Credits and Adjustments

'

433

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Loss Carryforwards, Adjustments, Additional Paid in Capital

'

178

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Loss Carryforwards, Adjustments, Income Tax Benefit

'

39

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Noncontrolling interest, ownership percentage by noncontrolling owners

'

20.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Severance costs

'

3

1

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Severance Costs, Expected Future Payments, Next Twelve Months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

Impairment and other charges

70

199

70

35

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Income Tax Benefit From Asset Impairment Charges

'

82

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Sales of Business

'

'

'

'

'

138

'

'

'

'

'

'

'

'

'

'

100

38

Obligation Period to Pay After Tax Proceeds from Realized Gains for Sale

'

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from sale of energy center

'

'

'

'

'

'

45

'

'

'

'

'

'

'

'

'

'

'

Pretax gain from sale of energy center

'

'

'

'

'

'

8

'

'

'

'

'

'

'

'

'

'

'

Proceeds from sales of additional properties and assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

Pretax gain from sales of additional properties and assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$4

'

'

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Schedule of Materials and Supplies) (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Accounting Policies [Abstract]	'		'
Fuel	$45	[1]	$48	[1]
Inventory, Raw Materials and Supplies, Gross	33		37
Total materials and supplies	$78		$85
[1]	Consists of coal for 2013 and coal and natural gas for 2012.

Summary_of_Significant_Account5

Summary of Significant Accounting Policies (Schedule of Asset Retirement Obligations) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Reconciliation of beginning and ending carrying amount of AROs [Roll Forward]	'		'
Balance	$59		$61
Liabilities incurred	3		2
Liabilities settled	-28	[1]	-5
Accretion in period	4		4
Change in estimates	5		-3
Balance	$43		$59
[1]	Under the terms of the agreement entered into on March 14, 2013 to divest New AER to IPH, Ameren retained the existing AROs associated with the closure of the Meredosia and Hutsonville facilities, which were estimated at $28 million as of the date of divestiture, December 2, 2013.

Summary_of_Significant_Account6

Summary of Significant Accounting Policies (Property, Plant and Equipment) (Details)	12 Months Ended
	Dec. 31, 2013
Minimum [Member]	'
Property, Plant and Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'1 year
Power Generation Facilities [Member] | Minimum [Member]	'
Property, Plant and Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'1 year
Power Generation Facilities [Member] | Maximum [Member]	'
Property, Plant and Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'30 years
Environmental Upgrades [Member] | Minimum [Member]	'
Property, Plant and Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'10 years
Environmental Upgrades [Member] | Maximum [Member]	'
Property, Plant and Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'30 years
Building and Building Improvements [Member] | Minimum [Member]	'
Property, Plant and Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'7 years
Building and Building Improvements [Member] | Maximum [Member]	'
Property, Plant and Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'36 years
Office Equipment [Member] | Minimum [Member]	'
Property, Plant and Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'2 years
Office Equipment [Member] | Maximum [Member]	'
Property, Plant and Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'15 years

Summary_of_Significant_Account7

Summary of Significant Accounting Policies (Asset Sales) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Long Lived Assets Held-for-sale [Line Items]	'	'
Assets held for sale	$0	$364
Liabilities held for sale	'	25
Materials and Supplies [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Assets held for sale	'	12
Mark To Market Derivative Assets [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Assets held for sale	'	4
Property, Plant and Equipment, Other Types [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Assets held for sale	'	348
Accounts and Wages Payable [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Liabilities held for sale	'	9
Accrued Income Taxes [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Liabilities held for sale	'	3
Mark-to-market derivative liabilities [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Liabilities held for sale	'	3
Asset Retirement Obligation Costs [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Liabilities held for sale	'	$10

Related_Party_Transactions_Nar

Related Party Transactions (Narrative) (Details) (USD $)	Oct. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Mar. 28, 2012	Dec. 31, 2012
In Millions, unless otherwise specified	employee	employee	Dynegy, Inc. [Member]	Ameren Transmission Company of Illinois [Member]	Put Option [Member]	Intercompany Transfer [Member]
						Ameren Energy Resources Generating Company [Member]
Related Party Transaction [Line Items]	'	'	'	'	'	'
Put option minimum purchase price	'	'	'	'	$100	'
Related party taxes payable	'	'	1	'	'	'
Number of employees transferred	52	74	'	'	'	'
Cash proceeds from transfer of assets	'	'	'	'	'	3
Cash proceeds from intercompany sale of land	'	'	'	2	'	'
Gain from intercompany sale of land	'	'	'	$2	'	'

Related_Party_Transactions_Phy

Related Party Transactions (Physical Gigawatthour Sales and Purchases) (Details) (Marketing Company [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	kWh	kWh	kWh
Genco (Parent) [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Sales to related party	12,111,000,000	11,933,000,000	14,293,000,000
EEI [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Sales to related party	6,856,000,000	6,421,000,000	7,633,000,000
Purchases from related party	29,000,000	22,000,000	886,000,000

Related_Party_Transactions_Sch

Related Party Transactions (Schedule of Related Party Transactions) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Related Party Transaction [Line Items]	'		'		'
Operating Revenues	$715		$805		$1,009
Genco and EEI Power Supply Agreements with Marketing Company [Member]	'		'		'
Related Party Transaction [Line Items]	'		'		'
Operating Revenues	709		804		1,006
Natural Gas Sales to Medina Valley [Member]	'		'		'
Related Party Transaction [Line Items]	'		'		'
Operating Revenues	0	[1]	1	[1]	3	[1]
AER Affiliates [Member]	'		'		'
Related Party Transaction [Line Items]	'		'		'
Operating Revenues	6		0		0
Ameren Missouri Gas Transportation Agreement [Member] | Fuel [Member]	'		'		'
Related Party Transaction [Line Items]	'		'		'
Operating Expenses	1		1		1
EEI Power Supply Agreement with Marketing Company [Member] | Purchased Power [Member]	'		'		'
Related Party Transaction [Line Items]	'		'		'
Operating Expenses	66		1		36
Ameren Services Support Services Agreement [Member] | Other Operations and Maintenance Expenses [Member]	'		'		'
Related Party Transaction [Line Items]	'		'		'
Operating Expenses	13		21		19
Money Pool Borrowings (Advances) [Member]	'		'		'
Related Party Transaction [Line Items]	'		'		'
Interest (Charges) Income (less than $1 million)	$1	[2]	$1	[2]	$1	[2]
[1]	Natural gas sold at fair value.
[2]	Amount less than $1 million.

Property_and_Plant_Net_Schedul

Property and Plant, Net (Schedule of Property and Plant, Net) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Property, Plant and Equipment [Abstract]	'	'
Property, plant and equipment	$2,551	$2,787
Less: Accumulated depreciation and amortization	-1,027	-1,192
Property and plant, before construction work in progress	1,524	1,595
Construction work in progress:	349	292
Property, plant and equipment, net	$1,873	$1,887

Property_and_Plant_Net_Accrued

Property and Plant, Net (Accrued Capital Expenditures) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Abstract]	'	'	'
Accrued capital expenditures	$3	$3	$13

ShortTerm_Debt_and_Liquidity_N

Short-Term Debt and Liquidity (Narrative) (Details) (Put Option [Member], Elgin, Gibson City and Grand Tower Energy Centers [Member], USD $)	0 Months Ended
In Millions, unless otherwise specified	Mar. 14, 2013	Oct. 11, 2013
	Initial Payment Received [Member]	Additional Payment Received [Member]
Line of Credit Facility [Line Items]	'	'
Proceeds from Sales of Business, Affiliate and Productive Assets	$100	$38

ShortTerm_Debt_and_Liquidity_B

Short-Term Debt and Liquidity (Borrowing Activity on Credit Agreements) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
	Ameren and Ameren Missouri [Member]	Ameren and Ameren Illinois [Member]	Money Pool [Member]	Genco Credit Agreement 2010 [Member]
Line of Credit Facility [Line Items]	'	'	'	'
Line of credit facility, maximum borrowing capacity	$1,000,000,000	$1,100,000,000	'	'
Weighted-average interest rate	'	'	0.61%	'
Outstanding credit facility borrowings at period end	'	'	0	0
Investment Income, Interest	'	'	$1,000,000	'

LongTerm_Debt_Schedule_of_Long

Long-Term Debt (Schedule of Long-Term Debt Outstanding) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Long-term debt, gross	$825,000,000	$825,000,000
Less: Unamortized discount and premium	-1,000,000	-1,000,000
Less: Maturities due within one year	0	0
Long-term debt, net	824,000,000	824,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]	'	'
2014	0	'
2015	0	'
2016	0	'
2017	0	'
2018	300,000,000	'
Thereafter	525,000,000	'
Off-balance sheet financing arrangements	0	'
Unsecured Debt [Member] | Senior Notes Series F 7.95% due 2032 [Member]	'	'
Debt Instrument [Line Items]	'	'
Debt instrument face amount	275,000,000	275,000,000
Long-term debt interest rate	7.95%	'
Long-term debt maturity date	'2032	'
Unsecured Debt [Member] | Senior Notes Series H 7.00% due 2018 [Member]	'	'
Debt Instrument [Line Items]	'	'
Debt instrument face amount	300,000,000	300,000,000
Long-term debt interest rate	7.00%	'
Long-term debt maturity date	'2018	'
Unsecured Debt [Member] | Senior Notes Series I 6.30% due 2020 [Member]	'	'
Debt Instrument [Line Items]	'	'
Debt instrument face amount	$250,000,000	$250,000,000
Long-term debt interest rate	6.30%	'
Long-term debt maturity date	'2020	'

LongTerm_Debt_Schedule_of_Requ

Long-Term Debt (Schedule of Required and Actual Debt Ratios) (Details)	12 Months Ended
	Dec. 31, 2013
Debt Instrument [Line Items]	'
Debt Instrument, Covenant Compliance, Dividend Restrictions, Interest Coverage Ratio Determination Period	'1 year
Debt Instrument, Covenant Compliance, Dividend Restrictions, Projected Interest Coverage Ratio Determination Period	'2 years
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]
[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.
[2]	Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Retirement_Benefits_Funded_Sta

Retirement Benefits (Funded Status Of Benefit Plans And Amounts Included In Regulatory Assets And OCI) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Amounts recognized in the balance sheet consist of:	'		'		'
Noncurrent liability	$18		$92		'
Pension Benefits [Member]	'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'
Accumulated benefit obligation at end of year	89		251		'
Change in benefit obligation:	'		'		'
Net benefit obligation at beginning of year	251		239		'
Service cost	5		5		6
Interest cost	10		10		11
Plan amendments	0	[1],[2]	-6	[1],[2]	'
Participant contributions	0		0		'
Actuarial loss	-11		3		'
Curtailments	0	[3]	2	[3]	'
Benefits paid	-22		-15		'
Defined Benefit Plan, Administration Expenses	-1		0		'
Net benefit obligation at end of year	89		251		239
Change in plan assets:	'		'		'
Fair value of plan assets at beginning of year	183		167		'
Actual return on plan assets	36		11		'
Employer contributions	15		11		12
Participant contributions	0		0		'
Benefits paid	-22		-15		'
Defined Benefit Plan, Administration Expenses	1		0		'
Fair value of plan assets at end of year	75		183		167
Funded status - deficiency	14		68		'
Amounts recognized in the balance sheet consist of:	'		'		'
Noncurrent asset	0	[4]	0	[4]	'
Current liability	0		0		'
Noncurrent liability	14		68		'
Net liability recognized	14		68		'
Amounts (pretax) recognized in accumulated OCI consist of:	'		'		'
Net actuarial loss	17		73		'
Prior service cost (credit)	-3		-10		'
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	14		63		'
Pension Benefits [Member] | Ameren [Member]	'		'		'
Change in benefit obligation:	'		'		'
Transfer of liability	-136	[5]	0	[5]	'
Change in plan assets:	'		'		'
Fair value of plan assets at beginning of year	117		'		'
Transfer of assets	-130	[5]	0	[5]	'
Fair value of plan assets at end of year	'		117		'
Pension Benefits [Member] | Ameren Services / Medina Valley [Member]	'		'		'
Change in benefit obligation:	'		'		'
Transfer of liability	-7	[6]	13	[6]	'
Change in plan assets:	'		'		'
Transfer of assets	-6	[6]	9	[6]	'
Pension Benefits [Member] | Dynegy, Inc. [Member]	'		'		'
Change in benefit obligation:	'		'		'
Transfer of liability	0	[7]	0	[7]	'
Change in plan assets:	'		'		'
Fair value of plan assets at end of year	1		'		'
Postretirement Benefits [Member]	'		'		'
Change in benefit obligation:	'		'		'
Net benefit obligation at beginning of year	93		150		'
Service cost	2		3		3
Interest cost	3		6		6
Plan amendments	-4	[1],[2]	-75	[1],[2]	'
Participant contributions	1		1		'
Actuarial loss	-8		15		'
Curtailments	1	[3]	-1	[3]	'
Benefits paid	-7		-8		'
Defined Benefit Plan, Administration Expenses	0		0		'
Net benefit obligation at end of year	50		93		150
Change in plan assets:	'		'		'
Fair value of plan assets at beginning of year	83		81		'
Actual return on plan assets	12		7		'
Employer contributions	0		0		'
Participant contributions	1		1		'
Benefits paid	-7		-8		'
Defined Benefit Plan, Administration Expenses	0		0		'
Fair value of plan assets at end of year	67		83		81
Funded status - deficiency	-17		10		'
Amounts recognized in the balance sheet consist of:	'		'		'
Noncurrent asset	-21	[4]	-14	[4]	'
Current liability	0		0		'
Noncurrent liability	4		24		'
Net liability recognized	-17		10		'
Amounts (pretax) recognized in accumulated OCI consist of:	'		'		'
Net actuarial loss	44		59		'
Prior service cost (credit)	-43		-62		'
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	1		-3		'
Postretirement Benefits [Member] | Ameren [Member]	'		'		'
Change in benefit obligation:	'		'		'
Transfer of liability	-33	[5]	0	[5]	'
Change in plan assets:	'		'		'
Fair value of plan assets at beginning of year	21		'		'
Transfer of assets	-21	[5]	0	[5]	'
Fair value of plan assets at end of year	'		21		'
Postretirement Benefits [Member] | Ameren Services / Medina Valley [Member]	'		'		'
Change in benefit obligation:	'		'		'
Transfer of liability	-2	[6]	2	[6]	'
Change in plan assets:	'		'		'
Transfer of assets	-1	[6]	2	[6]	'
Postretirement Benefits [Member] | Dynegy, Inc. [Member]	'		'		'
Change in benefit obligation:	'		'		'
Transfer of liability	4	[7]	0	[7]	'
Change in plan assets:	'		'		'
Fair value of plan assets at end of year	$1		'		'
[1]	In 2012, EEI's pension plan was amended to adjust the calculation of the future benefit obligation for all of its active management employees and certain union-represented employees from a traditional, final pay formula to a cash balance formula. Additionally, in 2012, EEI's management and union-represented postretirement medical benefit plans were amended to adjust for moving to a Medicare Advantage plan.
[2]	Effective with the AER Acquisition, the EEI management postretirement plan was remeasured as a result of a reduction in employees participating in the postretirement plan. This remeasurement reduced the benefit obligation, resulting in the establishment of a prior service credit.
[3]	Effective with the AER Acquisition, there was a reduction in employees who participated in the EEI management postretirement plan which resulted in a curtailment of the plan. EEI implemented an employee reduction program in 2012, which resulted in a curtailment of its pension and management postretirement benefit plans.
[4]	The EEI union postretirement plan was over-funded as of December 31, 2013 and 2012 and the EEI management postretirement plan was over-funded as of December 31, 2013, which was included in our balance sheets in “Other assets.”
[5]	Effective with the AER Acquisition, Ameren retained the portion of Genco’s pension obligations associated with the current and former employees of Genco and the portion of Genco’s postretirement benefit obligations associated with the employees of Genco who were eligible to retire at December 2, 2013 with respect to such employees’ participation in Ameren’s single-employer pension and postretirement plans.
[6]	In October 2013, 52 employees from Genco were transferred to Ameren Services and Medina Valley through an internal reorganization. On December 31, 2012, 74 employees from Ameren Services were transferred to Genco through an internal reorganization.
[7]	Amount represents the allocation of the obligation from our participation in Dynegy’s single-employer plans.

Retirement_Benefits_Assumption

Retirement Benefits (Assumptions Used To Determine Benefit Obligations) (Details)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Pension Benefits [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Discount rate at measurement date	4.82%	[1]	4.00%	[1]
Increase in future compensation	3.50%	[1]	4.48%	[1]
Postretirement Benefits [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Discount rate at measurement date	4.78%	[1]	4.00%	[1]
Increase in future compensation	3.50%	[1]	4.41%	[1]
Ameren [Member] | Postretirement Benefits [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Medical cost trend rate (initial)	'		5.00%
Medical cost trend rate (ultimate)	'		5.00%
Years to ultimate rate	'		'0 years
EEI [Member] | Postretirement Benefits [Member]	'		'
Defined Benefit Plan Disclosure [Line Items]	'		'
Medical cost trend rate (initial)	7.75%		7.96%
Medical cost trend rate (ultimate)	4.50%		4.50%
Years to ultimate rate	'10 years		'15 years
[1]	A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans at December 31, 2013. A weighted average rate of EEI’s and Ameren’s pension and postretirement plans at December 31, 2012.

Retirement_Benefits_Cash_Contr

Retirement Benefits (Cash Contributions Made To Benefit Plans) (Details) (Pension Benefits [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'		'		'
Cash contributions to benefit plans	$15		$11		$12
Genco (Parent) [Member]	'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'
Cash contributions to benefit plans	5	[1]	4	[1]	4	[1]
EEI [Member]	'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'
Cash contributions to benefit plans	$10		$7		$8
[1]	Represents an allocation of our share of cash contributions associated with our participation in Ameren’s pension plans.

Retirement_Benefits_Target_All

Retirement Benefits (Target Allocation Of The Plans' Asset Categories) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target Allocation	100.00%	'
Percentage of Plan Assets	100.00%	100.00%
Pension Benefits [Member] | Equity securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target Allocation	60.00%	'
Percentage of Plan Assets	61.00%	59.00%
Pension Benefits [Member] | Debt securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target Allocation	40.00%	'
Percentage of Plan Assets	39.00%	38.00%
Pension Benefits [Member] | Cash and cash equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target Allocation	0.00%	'
Percentage of Plan Assets	0.00%	3.00%
Postretirement Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target Allocation	100.00%	'
Percentage of Plan Assets	100.00%	100.00%
Postretirement Benefits [Member] | Equity securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target Allocation	60.00%	'
Percentage of Plan Assets	60.00%	62.00%
Postretirement Benefits [Member] | Debt securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target Allocation	40.00%	'
Percentage of Plan Assets	38.00%	36.00%
Postretirement Benefits [Member] | Cash and cash equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target Allocation	0.00%	'
Percentage of Plan Assets	2.00%	2.00%

Retirement_Benefits_Fair_Value

Retirement Benefits (Fair Value Of Plan Assets Utilizing Fair Value Hierarchy) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	$75	$183	$167
Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	67	83	81
EEI [Member] | Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	75	66	'
EEI [Member] | Pension Benefits [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Pension Benefits [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	75	66	'
EEI [Member] | Pension Benefits [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Pension Benefits [Member] | Cash and cash equivalents [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	2	'
EEI [Member] | Pension Benefits [Member] | Cash and cash equivalents [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Pension Benefits [Member] | Cash and cash equivalents [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	2	'
EEI [Member] | Pension Benefits [Member] | Cash and cash equivalents [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Pension Benefits [Member] | U.S. large capitalization [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	26	22	'
EEI [Member] | Pension Benefits [Member] | U.S. large capitalization [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Pension Benefits [Member] | U.S. large capitalization [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	26	22	'
EEI [Member] | Pension Benefits [Member] | U.S. large capitalization [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Pension Benefits [Member] | U.S. small capitalization [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	14	12	'
EEI [Member] | Pension Benefits [Member] | U.S. small capitalization [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Pension Benefits [Member] | U.S. small capitalization [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	14	12	'
EEI [Member] | Pension Benefits [Member] | U.S. small capitalization [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Pension Benefits [Member] | International [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	6	5	'
EEI [Member] | Pension Benefits [Member] | International [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Pension Benefits [Member] | International [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	6	5	'
EEI [Member] | Pension Benefits [Member] | International [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Pension Benefits [Member] | Debt Securities [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	29	25	'
EEI [Member] | Pension Benefits [Member] | Debt Securities [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Pension Benefits [Member] | Debt Securities [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	29	25	'
EEI [Member] | Pension Benefits [Member] | Debt Securities [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	67	62	'
EEI [Member] | Postretirement Benefits [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	55	39	'
EEI [Member] | Postretirement Benefits [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	12	23	'
EEI [Member] | Postretirement Benefits [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Postretirement Benefits [Member] | Cash and cash equivalents [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	1	1	'
EEI [Member] | Postretirement Benefits [Member] | Cash and cash equivalents [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	1	0	'
EEI [Member] | Postretirement Benefits [Member] | Cash and cash equivalents [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	1	'
EEI [Member] | Postretirement Benefits [Member] | Cash and cash equivalents [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Postretirement Benefits [Member] | U.S. large capitalization [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	33	32	'
EEI [Member] | Postretirement Benefits [Member] | U.S. large capitalization [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	33	32	'
EEI [Member] | Postretirement Benefits [Member] | U.S. large capitalization [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Postretirement Benefits [Member] | U.S. large capitalization [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Postretirement Benefits [Member] | International [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	8	7	'
EEI [Member] | Postretirement Benefits [Member] | International [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	8	7	'
EEI [Member] | Postretirement Benefits [Member] | International [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Postretirement Benefits [Member] | International [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Postretirement Benefits [Member] | U.S. treasury and agency securities [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	14	11	'
EEI [Member] | Postretirement Benefits [Member] | U.S. treasury and agency securities [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	13	0	'
EEI [Member] | Postretirement Benefits [Member] | U.S. treasury and agency securities [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	1	11	'
EEI [Member] | Postretirement Benefits [Member] | U.S. treasury and agency securities [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Postretirement Benefits [Member] | Municipal bonds [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	5	5	'
EEI [Member] | Postretirement Benefits [Member] | Municipal bonds [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Postretirement Benefits [Member] | Municipal bonds [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	5	5	'
EEI [Member] | Postretirement Benefits [Member] | Municipal bonds [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Postretirement Benefits [Member] | Corporate bonds [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	6	6	'
EEI [Member] | Postretirement Benefits [Member] | Corporate bonds [Member] | Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
EEI [Member] | Postretirement Benefits [Member] | Corporate bonds [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	6	6	'
EEI [Member] | Postretirement Benefits [Member] | Corporate bonds [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	$0	$0	'

Retirement_Benefits_Summary_Of

Retirement Benefits (Summary Of Estimated Amortizable Amounts From Regulatory Assets and Accumulated OCI Into Net Periodic Benefit Cost) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Pension Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Prior service cost (credit)	$0	[1]
Net actuarial loss	1	[1]
Net periodic benefit cost	1	[1]
Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Prior service cost (credit)	-4	[1]
Net actuarial loss	3	[1]
Net periodic benefit cost	($1)	[1]
[1]	Includes only amounts for EEI’s plans.

Retirement_Benefits_Components

Retirement Benefits (Components Of Net Periodic Benefit Cost) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'		'		'
Curtailment gain on pension and postretirement benefit plans	($26)		$0		$0
Pension Benefits [Member]	'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'
Service cost	5		5		6
Interest cost	10		10		11
Expected return on plan assets	-13		-13		-13
Prior service cost	-1		-1		0
Actuarial loss	6		6		3
Defined Benefit Plan, Settlements, Benefit Obligation	1		'		'
Curtailment gain on pension and postretirement benefit plans	0	[1]	2	[2]	'
Net periodic benefit cost	8		9		7
Postretirement Benefits [Member]	'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'
Service cost	2		3		3
Interest cost	3		6		6
Expected return on plan assets	-5		-6		-6
Prior service cost	-8		-3		-3
Actuarial loss	5		4		2
Defined Benefit Plan, Settlements, Benefit Obligation	0		'		'
Curtailment gain on pension and postretirement benefit plans	-26	[1]	0	[2]	'
Net periodic benefit cost	($29)		$4		$2
[1]	Represents EEI’s management postretirement benefit plans’ curtailment gain recognized due to a reduction of employees as a result of the AER Acquisition.
[2]	Represents EEI’s pension and management postretirement benefit plans’ curtailment loss recognized as a result of its 2012 employee reduction program.

Retirement_Benefits_Schedule_O

Retirement Benefits (Schedule Of Expected Payments From Qualified Trust And Company Funds) (Details) (Paid From Qualified Trust [Member], USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Pension Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
2014	$14	[1]
2015	6	[1]
2016	7	[1]
2017	7	[1]
2018	7	[1]
2019 - 2023	32	[1]
Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
2014	3	[1]
2015	3	[1]
2016	3	[1]
2017	3	[1]
2018	3	[1]
2019 - 2023	$14	[1]
[1]	Includes only amounts for EEI’s plans.

Retirement_Benefits_Assumption1

Retirement Benefits (Assumptions Used To Determine Net Periodic Benefit Cost) (Details)

12 Months Ended

11 Months Ended

1 Months Ended

11 Months Ended

12 Months Ended

11 Months Ended

12 Months Ended

1 Months Ended

11 Months Ended

1 Months Ended

11 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 02, 2013

Dec. 31, 2013

Dec. 02, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 02, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 02, 2013

Dec. 31, 2013

Dec. 02, 2013

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Ameren [Member]

EEI [Member]

EEI [Member]

Ameren [Member]

Ameren [Member]

Ameren [Member]

EEI [Member]

EEI [Member]

EEI [Member]

EEI [Member]

EEI [Member]

EEI [Member]

EEI [Member]

EEI [Member]

Union Employees [Member]

Union Employees [Member]

Management [Member]

Management [Member]

Defined Benefit Plan Disclosure [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Discount rate at measurement date

'

4.36%

[1]

5.33%

[1]

'

4.67%

4.00%

'

4.29%

[1]

5.39%

[1]

'

'

'

4.00%

'

'

'

4.00%

'

4.75%

'

Expected return on plan assets

7.65%

[1]

7.84%

[1]

8.00%

[1]

'

'

'

7.59%

[1]

7.87%

[1]

7.93%

[1]

'

'

'

'

'

'

'

'

'

'

'

Increase in future compensation

'

3.70%

[1]

3.70%

[1]

3.50%

3.50%

5.97%

'

3.86%

[1]

3.83%

[1]

'

'

'

'

'

'

'

6.35%

6.35%

3.50%

3.81%

Defined Benefit Plan Assumption Used Calculating Net Periodic Benefit Costs Health Care Costs Trend Rate Assumed For Next Fiscal Year

'

'

'

'

'

'

'

'

'

5.00%

5.50%

6.00%

7.96%

'

8.30%

8.65%

7.96%

'

7.75%

'

Medical cost trend rate (initial)

'

'

'

'

'

'

'

'

'

5.00%

5.00%

5.00%

'

4.50%

4.50%

4.50%

'

'

'

'

Years to ultimate rate

'

'

'

'

'

'

'

'

'

'0 years

'1 year

'2 years

'14 years

'

'15 years

'16 years

'14 years

'

'10 years

'

[1]

EEI’s and Ameren’s pension and postretirement plans.(b)The discount rate used for EEI’s pension plan was 4.00% and 4.67% for the period from January 1, 2013 through December 1, 2013 and the period from December 2, 2013 through December 31, 2013, respectively. The discount rate used for Ameren’s pension plans was 4.00% for the period from January 1, 2013 through December 1, 2013.(c)The discount rate used for EEI’s postretirement plans was 4.00% for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 4.00% for EEI union employees and 4.75% for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively. The discount rate used for Ameren’s postretirement plans was 4.00% for the period from January 1, 2013 through December 1, 2013.(d)The average rate of compensation increase used for EEI’s pension plan was 5.97% and 3.50% for the period from January 1, 2013 through December 1, 2013 and the period from December 2, 2013 through December 31, 2013, respectively. The average rate of compensation increase used for Ameren’s pension plans was 3.50% for the period from January 1, 2013 through December 1, 2013.(e)The average rate of compensation increase used for EEI’s postretirement plans was 6.35% for EEI union employees and 3.81% for EEI management employees for the period from January 1, 2013 through December 1, 2013 and 6.35% for EEI union employees and 3.50% for EEI management employees and the period from December 2, 2013 through December 31, 2013, respectively. The average rate of compensation increase used for Ameren’s postretirement plans was 3.50% for the period from January 1, 2013 through December 1, 2013.(f)The initial medical cost trend rate used for EEI’s postretirement plans was 7.96% for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 7.96% for EEI union employees and 7.75% for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively. (g)The years to ultimate trend rate used for EEI’s postretirement plans was 14 years for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 14 years for EEI union employees and 10 years for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively.

Retirement_Benefits_Schedule_O1

Retirement Benefits (Schedule Of Potential Changes In Key Assumptions) (Details) (Postretirement Benefits [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Service Cost and Interest Cost, 1.00% increase in annual medical trend	$1	[1]
Benefit Obligation, 1.00% increase in annual medical trend	5	[1]
Service Cost and Interest Cost, 1.00% decrease in annual medical trend	0	[1]
Benefit Obligation, 1.00% decrease in annual medical trend	($4)	[1]
[1]	Includes amounts for EEI’s plans and our participation in Dynegy’s plans.

Retirement_Benefits_Narrative_

Retirement Benefits (Narrative) (Details) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

11 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Oct. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 02, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

employee

employee

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Electric Energy Inc Pension Plan [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Ameren [Member]

Ameren [Member]

Ameren [Member]

Ameren [Member]

Ameren [Member]

Ameren Services [Member]

Ameren Services [Member]

Ameren Services [Member]

Ameren Services [Member]

Ameren Services [Member]

Ameren Services [Member]

Electric Energy, Inc. [Member]

Electric Energy, Inc. [Member]

Electric Energy, Inc. [Member]

Electric Energy, Inc. [Member]

Electric Energy, Inc. [Member]

Electric Energy, Inc. [Member]

Electric Energy, Inc. [Member]

Electric Energy, Inc. [Member]

Dynegy, Inc. [Member]

Dynegy, Inc. [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Union Employees [Member]

Management [Member]

Defined Contribution Pension [Member]

Defined Contribution Pension [Member]

Defined Contribution Pension [Member]

Pension Benefits [Member]

Postretirement Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Defined Contribution Pension [Member]

Defined Contribution Pension [Member]

Defined Contribution Pension [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Pension Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Postretirement Benefits [Member]

Electric Energy, Inc. [Member]

Electric Energy, Inc. [Member]

Postretirement Benefit Costs [Member]

Postretirement Benefit Costs [Member]

Retirement Benefits [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Curtailment gain on pension and postretirement benefits

($26)

$0

$0

'

$0

[1]

$2

[2]

'

'

($26)

[1]

$0

[2]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$26

[1]

'

'

'

'

'

'

'

'

Estimated pension and postretirement benefit obligations

'

'

'

'

89

251

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of employees transferred

'

74

'

52

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Funded (unfunded) status

'

'

'

'

-14

-68

'

'

17

-10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other non-current assets

28

26

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated contributions in 2014

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Defined benefit plan, estimated future employer contributions during the next five years

'

'

'

'

'

'

'

15

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Employer contributions (less than $1 million for postretirement plans)

'

'

'

'

15

11

12

'

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10

7

8

'

'

'

'

1

1

1

'

'

Assumptions used calculating net periodic benefit cost, expected long-term return on assets in 2014

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.25%

'

'

'

'

'

'

'

'

'

6.50%

5.50%

Fair value of plan assets

'

'

'

'

75

183

167

'

67

83

81

'

'

'

117

21

'

'

'

'

'

'

'

'

'

75

66

'

67

62

1

1

'

'

'

'

'

Net periodic benefit cost

'

'

'

'

8

9

7

'

-29

4

2

'

'

'

'

'

1

2

1

1

1

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Genco's portion of matching contribution to the Ameren 401(k) plan

'

'

'

'

'

'

'

'

'

'

'

$1

$1

$2

'

'

'

'

'

'

'

'

$1

$1

$1

'

'

'

'

'

'

'

'

'

'

'

'

[1]

Represents EEI’s management postretirement benefit plans’ curtailment gain recognized due to a reduction of employees as a result of the AER Acquisition.

[2]

Represents EEI’s pension and management postretirement benefit plans’ curtailment loss recognized as a result of its 2012 employee reduction program.

Income_Taxes_Schedule_Of_Effec

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'		'	'
Statutory federal income tax rate:	35.00%		35.00%	35.00%
Tax credits	0.00%		-2.00%	-1.00%
Amortization of investment tax credit	0.00%		0.00%	-1.00%
State tax	6.00%		7.00%	6.00%
Effective Income Tax Rate Reconciliation, Deductions, Qualified Production Activities	0.00%		0.00%	3.00%
Reserve for uncertain tax positions	0.00%		2.00%	0.00%
Effective Income Tax Rate Reconciliation, Deductions, Other	-15.00%	[1]	0.00%	0.00%
Effective income tax rate	26.00%		42.00%	42.00%
[1]	Acquisition adjustment is primarily the result of the loss of expected benefits from the NOL carryforward in existence at the Acquisition Date due to IRC Section 382 limits.

Income_Taxes_Schedule_Of_Compo

Income Taxes (Schedule Of Components Of Income Tax Expense (Benefit)) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Current Federal taxes	($50)	($15)	($21)
Current State taxes	-14	-5	-7
Deferred Federal taxes	6	-6	43
Deferred State taxes	-6	-2	18
Deferred investment tax credits, amortization	-1	-1	-1
Total income tax expense	($65)	($29)	$32

Income_Taxes_Schedule_Of_Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities Resulting From Temporary Differences) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Income Tax Disclosure [Abstract]	'	'
Plant related	$541	$424
Deferred benefit costs	-24	-37
ARO	-16	-28
Other	38	-36	[1]
Total net accumulated deferred income tax liabilities	539	323	[2]
Current assets	'	$11
[1]	Included deferred tax assets related to net operating loss and tax credit carryforwards as of December 31, 2012.
[2]	Includes $11 million in “Other current assets” on the balance sheet as of December 31, 2012.

Income_Taxes_Schedule_Of_Chang

Income Taxes (Schedule Of Changes To Unrecognized Tax Benefits And Related Interest) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Unrecognized tax benefits	$6	$9	$20
Increases based on tax positions	2	1	1
Decreases based on tax positions	-3	-2	-12
Increases based on tax positions related to current period	0	0	1
Decreases based on tax positions related to current year	-1	-1	0
Unrecognized Tax Benefits, Decreases Resulting from Acquisition	-3	0	0
Decreases related to the lapse of statute of limitations	-1	-1	-1
Unrecognized tax benefits	0	6	9
Total unrecognized tax benefits (detriments) that, if recognized, would impact the effective tax rates	$0	$0	$1

Income_Taxes_Reconciliation_Of

Income Taxes (Reconciliation Of The Change In The Liability For Interest On Unrecognized Tax Benefits) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Liability for interest - beginning of year	$1	$1	$2
Interest charges (income)	0	0	-1
Adjustment of balance due to change in ownership	-1	0	0
Liability for interest - end of year	$0	$1	$1

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended				1 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012	Jan. 31, 2011	Jan. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
				Illinois Corporate Income Tax [Member]	Minimum [Member]	Maximum [Member]	Income Tax Rate in 2015 [Member]	Income Tax Rate in 2025 [Member]	Dynegy, Inc. [Member]
					Illinois Corporate Income Tax [Member]	Illinois Corporate Income Tax [Member]	Illinois Corporate Income Tax [Member]	Illinois Corporate Income Tax [Member]
Income Taxes [Line Items]	'	'	'	'	'	'	'	'	'
Current portion of tax payable	'	'	'	'	'	'	'	'	$1,000,000
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	-254,000,000	-69,000,000	77,000,000	'	'	'	'	'	'
State corporate income tax rate	6.00%	7.00%	6.00%	'	7.30%	9.50%	7.75%	7.30%	'
Increase in current state and local tax expense benefit	'	'	'	3,000,000	'	'	'	'	'
Amount accrued for penalties with respect to unrecognized tax benefits	0	0	0	'	'	'	'	'	'
Reduction of uncertain tax positions	'	4,000,000	'	'	'	'	'	'	'
Operating Loss Carryforwards	0	'	'	'	'	'	'	'	'
Income Tax Credits and Adjustments	433,000,000	'	'	'	'	'	'	'	'
Operating Loss Carryforwards, Adjustments, Additional Paid in Capital	178,000,000	'	'	'	'	'	'	'	'
Operating Loss Carryforwards, Adjustments, Income Tax Benefit	$39,000,000	'	'	'	'	'	'	'	'

Derivative_Financial_Instrumen2

Derivative Financial Instruments (Open Gross Derivative Volumes By Commodity Type) (Details) (Other Contract [Member])	Dec. 31, 2013		Dec. 31, 2012
	T		T
Coal [Member]	'		'
Derivative [Line Items]	'		'
Quantity	0		5,000,000
Fuel Oils [Member]	'		'
Derivative [Line Items]	'		'
Quantity	0	[1]	40,000,000	[1]
Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Quantity	0		42,000,000
Power [Member]	'		'
Derivative [Line Items]	'		'
Quantity	0		0
[1]	Fuel oils consist of heating and crude oil.(b)Amounts include commodity contracts classified as held for sale.

Derivatives_Derivative_Instrum

Derivatives (Derivative Instruments Carrying Value) (Details) (Not Designated As Hedging Instrument [Member], USD $)	Dec. 31, 2012
In Millions, unless otherwise specified
Derivative [Line Items]	'
Derivative assets	$8
Derivative liabilities	15
Coal [Member] | Other assets [Member]	'
Derivative [Line Items]	'
Derivative assets	1
Coal [Member] | Mark-to-market derivative liabilities [Member]	'
Derivative [Line Items]	'
Derivative liabilities	7
Coal [Member] | Other deferred credits and liabilities [Member]	'
Derivative [Line Items]	'
Derivative liabilities	3
Fuel Oils [Member] | Other assets [Member]	'
Derivative [Line Items]	'
Derivative assets	1
Fuel Oils [Member] | Other current assets [Member]	'
Derivative [Line Items]	'
Derivative assets	2
Fuel Oils [Member] | Mark-to-market 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] | Other current assets [Member]	'
Derivative [Line Items]	'
Derivative assets	4
Natural Gas [Member] | Mark-to-market derivative liabilities [Member]	'
Derivative [Line Items]	'
Derivative liabilities	$3

Derivative_Financial_Instrumen3

Derivative Financial Instruments (Maximum Exposure If Counterparties Fail To Perform On Contracts) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
Concentration Risk [Line Items]	'
Maximum exposure to counterparties related to derivative contracts	$7
Coal Producers [Member]	'
Concentration Risk [Line Items]	'
Maximum exposure to counterparties related to derivative contracts	2
Commodity Marketing Companies [Member]	'
Concentration Risk [Line Items]	'
Maximum exposure to counterparties related to derivative contracts	1
Electric Utilities [Member]	'
Concentration Risk [Line Items]	'
Maximum exposure to counterparties related to derivative contracts	0
Financial Companies [Member]	'
Concentration Risk [Line Items]	'
Maximum exposure to counterparties related to derivative contracts	2
Oil And Gas Companies [Member]	'
Concentration Risk [Line Items]	'
Maximum exposure to counterparties related to derivative contracts	$2

Derivative_Financial_Instrumen4

Derivative Financial Instruments (Potential Loss On Counterparty Exposures) (Details) (USD $)	Dec. 31, 2012
In Millions, unless otherwise specified
Concentration Risk [Line Items]	'
Potential loss on counterparty exposures related to derivative contracts	$2
Coal Producers [Member]	'
Concentration Risk [Line Items]	'
Potential loss on counterparty exposures related to derivative contracts	1
Commodity Marketing Companies [Member]	'
Concentration Risk [Line Items]	'
Potential loss on counterparty exposures related to derivative contracts	0
Electric Utilities [Member]	'
Concentration Risk [Line Items]	'
Potential loss on counterparty exposures related to derivative contracts	0
Financial Companies [Member]	'
Concentration Risk [Line Items]	'
Potential loss on counterparty exposures related to derivative contracts	1
Oil And Gas Companies [Member]	'
Concentration Risk [Line Items]	'
Potential loss on counterparty exposures related to derivative contracts	$0

Derivative_Financial_Instrumen5

Derivative Financial Instruments (Derivative Instruments With Credit Risk-Related Contingent Features) (Details) (USD $)	Dec. 31, 2012
In Millions, unless otherwise specified
Derivative Instrument Detail [Abstract]	'
Aggregate Fair Value of Derivative Liabilities	$48	[1]
Cash Collateral Posted	0
Potential Aggregate Amount of Additional Collateral Required	$31
[1]	Prior to consideration of master trading and netting agreements and including accrual and NPNS contract exposures.

Derivative_Financial_Instrumen6

Derivative Financial Instruments (Cash Flow Hedges) (Details) (Interest Rate Swap [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Derivative [Line Items]	'		'
Gain (Loss) Recognized in OCI	$0	[1],[2]	$0	[1],[2]
Cash flow hedge gain (loss) reclassified to revenue, amortization period	'10 years		'
Interest Charges [Member]	'		'
Derivative [Line Items]	'		'
(Gain) Loss Reclassified from Accumulated OCI	1	[2],[3]	1	[2],[3]
Gain (Loss) Recognized in Income	$0	[2],[4]	$0	[2],[4]
[1]	Effective portion of gain (loss).
[2]	Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.
[3]	Effective portion of (gain) loss on settlements.
[4]	Ineffective portion of gain (loss) and amount excluded from effectiveness testing.

Derivative_Financial_Instrumen7

Derivative Financial Instruments (Other Derivatives) (Details) (Not Designated As Hedging Instrument [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]	'	'
Gain (Loss) Recognized in Income	$7	($18)
Coal [Member] | Operating Expenses - Fuel [Member]	'	'
Derivative [Line Items]	'	'
Gain (Loss) Recognized in Income	9	-9
Fuel Oils [Member] | Operating Expenses - Fuel [Member]	'	'
Derivative [Line Items]	'	'
Gain (Loss) Recognized in Income	-1	-9
Natural Gas (Generation) [Member] | Operating Expenses - Fuel [Member]	'	'
Derivative [Line Items]	'	'
Gain (Loss) Recognized in Income	-1	0
Power [Member] | Operating Revenues - Electric [Member]	'	'
Derivative [Line Items]	'	'
Gain (Loss) Recognized in Income	$0	$0

Derivative_Financial_Instrumen8

Derivative Financial Instruments (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]	'	'
Counterparty letters of credit held as collateral	$0	$1
Interest Rate Swap [Member]	'	'
Derivative [Line Items]	'	'
Cumulative deferred pretax gains (losses)	6	7
Cash flow hedge gain (loss) reclassified to revenue, amortization period	'10 years	'
Loss amortized over the next 12 months	($1)	'

Fair_Value_Measurements_Schedu

Fair Value Measurements (Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis) (Details) (Commodity Contracts [Member], USD $)	Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Derivative assets	($8)	[1]
Derivative liabilities	15	[1]
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	-7	[1]
Derivative liabilities	15	[1]
Significant Other Observable Inputs (Level 2) [Member]	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Derivative assets	0	[1]
Derivative liabilities	0	[1]
Significant Other Unobservable Inputs (Level 3) [Member]	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Derivative assets	-1	[1]
Derivative liabilities	0	[1]
Coal [Member]	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Derivative assets	-1	[1]
Derivative liabilities	10	[1]
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	[1]
Derivative liabilities	10	[1]
Coal [Member] | Significant Other Observable Inputs (Level 2) [Member]	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Derivative assets	0	[1]
Derivative liabilities	0	[1]
Coal [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Derivative assets	0	[1]
Derivative liabilities	0	[1]
Fuel Oils [Member]	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Derivative assets	-3	[1]
Derivative liabilities	2	[1]
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	-2	[1]
Derivative liabilities	2	[1]
Fuel Oils [Member] | Significant Other Observable Inputs (Level 2) [Member]	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Derivative assets	0	[1]
Derivative liabilities	0	[1]
Fuel Oils [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Derivative assets	-1	[1]
Derivative liabilities	0	[1]
Natural Gas [Member]	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Derivative assets	-4	[1]
Derivative liabilities	3	[1]
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	[1]
Derivative liabilities	3	[1]
Natural Gas [Member] | Significant Other Observable Inputs (Level 2) [Member]	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Derivative assets	0	[1]
Derivative liabilities	0	[1]
Natural Gas [Member] | Significant Other Unobservable Inputs (Level 3) [Member]	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'
Derivative assets	0	[1]
Derivative liabilities	$0	[1]
[1]	The derivative asset and liability balances are presented net of counterparty credit considerations.

Fair_Value_Measurements_Schedu1

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) (Fuel Oils [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fuel Oils [Member]	'	'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]	'	'
Beginning balance	$1	$1
Included in earnings	0	0
Total realized and unrealized gains (losses)	0	0
Purchases	0	0
Settlements	-1	0
Transfers into Level 3	0	1
Transfers out of Level 3	0	-1
Ending balance	0	1
Change in unrealized gains (losses) related to assets/liabilities still held	$0	$0

Fair_Value_Measurements_Schedu2

Fair Value Measurements (Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt And Preferred Stock) (Details) (USD $)	Dec. 31, 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 (including current portion)	$824	$824
Fair Value [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term debt (including current portion)	$683	$618

Commitments_and_Contingencies_

Commitments and Contingencies (Environmental Matters) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
	state
	option
Loss Contingencies [Line Items]	'
Environmental Remediation Obligations, Permitting Matters, Statute of Limitations	'5 years
Estimated capital costs to comply with existing and known federal and state air emissions regulations	$45
Number of states participating in the cap-and-trade program	28
Percent of top performing facilities	12.00%
Environmental Matters, Proposed Regulations, Number of Options	2
Minimum [Member]	'
Loss Contingencies [Line Items]	'
Environmental Obligations, Period of Significant Capital Expenditure or Increased Operating Costs	'5 years
Maximum [Member]	'
Loss Contingencies [Line Items]	'
Environmental Obligations, Period of Significant Capital Expenditure or Increased Operating Costs	'10 years
Environmental Protection Agency [Member]	'
Loss Contingencies [Line Items]	'
Environmental Remediation Obligations, Permitting Matters, Statute of Limitations	'5 years
Public Utilities, Plan Development Period	'18 months
Public Utilities, Plan Achievement Period	'5 years
Number of Facilities Located in Designated Nonattainment by EPA	0
Public Utilities, Clean Water Act, Compliance Period	'8 years
Coffeen Facility [Member]	'
Loss Contingencies [Line Items]	'
Public Utilities, Phase-In Modifications, MPS and Other Air Emissions Laws and Regulations, Emission Reducing Equipment	2
Newton Facility [Member]	'
Loss Contingencies [Line Items]	'
Public Utilities, Phase-In Modifications, MPS and Other Air Emissions Laws and Regulations, Emission Reducing Equipment	2

Commitments_and_Contingencies_1

Commitments and Contingencies (Guaranty and Other Commitments) (Details) (USD $)	12 Months Ended						0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 02, 2013
				Coal Commitments [Member]	Coal Transportation Contracts [Member]	Employee Severance [Member]	IPH [Member]
							Guaranty [Member]
Long-term Purchase Commitment [Line Items]	'	'	'	'	'	'	'
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High	'	'	'	'	'	'	$25
Unrecorded Unconditional Purchase Obligation	'	'	'	366	279	'	'
Number Of Years To Acquisition Closing	'	'	'	'	'	'	'2 years
Operating Leases, Rent Expense	4	4	2	'	'	'	'
Severance Costs, Expected Future Payments, Next Twelve Months	'	'	'	'	'	3	'
Facilities Service Agreement, Expected Future Payments	$4	'	'	'	'	'	'
Facilities Service Agreement, Period	'26 years	'	'	'	'	'	'

Commitments_and_Contingencies_2

Commitments and Contingencies (Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity) (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]	'
2014, less than	$1
2015, less than	1
2016, less than	1
2017, less than	1
2018, less than	$1

Impairment_and_Other_Charges_S

Impairment and Other Charges (Summary Of Goodwill And Other Asset Impairment Pretax Charges) (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Goodwill and Intangible Assets Disclosure [Abstract]	'	'	'	'
Impairment charge on long-lived assets and related charges	'	$199	$70	$34
Impairment charge on emission allowances	'	0	0	1
Total impairment charge	$70	$199	$70	$35

Impairment_and_Other_Charges_N

Impairment and Other Charges (Narrative) (Details) (USD $)	3 Months Ended	12 Months Ended			1 Months Ended		0 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2011	Jul. 31, 2011	Mar. 14, 2013
					Closure of Meredosia and Hutsonville Energy Centers [Member]	SO2 Emission Allowances [Member]	Significant Other Unobservable Inputs (Level 3) [Member]
							Put Option [Member]
							Elgin, Gibson City and Grand Tower Energy Centers [Member]
Impairment and Other Charges [Line Items]	'	'	'	'	'	'	'
Impairment and other charges	$70,000,000	$199,000,000	$70,000,000	$35,000,000	'	'	'
Proceeds from Sales of Business, Affiliate and Productive Assets	'	'	'	'	'	'	138,000,000
Impairment charge on long-lived assets and related charges	'	199,000,000	70,000,000	34,000,000	26,000,000	'	'
Non-cash impairment of materials and supplies	'	'	'	'	4,000,000	'	'
Income Tax Benefit From Asset Impairment Charges	'	82,000,000	'	'	'	'	'
Severance costs	'	3,000,000	1,000,000	4,000,000	4,000,000	'	'
Amount of Fair Value in Excess of Carrying Amount	'	1,000,000,000	'	'	'	'	'
Pretax impairment charge	'	$0	$0	$1,000,000	'	$1,000,000	'

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Loss) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'		'		'
Beginning of period	($40)		($72)		'
Actuarial gain and plan amendments (net of tax expense of $8 and $20, respectively)	12		28		'
Reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges, net (net of tax benefit of zero and zero, respectively) (a)	1	[1]	1	[1]	1
Amortization of unrecognized prior service cost and actuarial gain (loss) (net of tax expense of $1 and $2, respectively) (b)	1	[2]	3	[2]	'
Amounts reclassified from accumulated other comprehensive income (loss) (net of tax benefit of $9 and zero, respectively) (c)	-13	[3]	0	[3]	'
Amounts reclassified from accumulated other comprehensive income (loss) (net of tax benefit of $9 and zero, respectively) (c)	-11		4		'
Net current period other comprehensive income (loss), net of tax	1		32		'
AER Acquisition (net of tax expense of $20 and zero, respectively) (d)	28	[4]	0	[4]	'
End of period	-11		-40		-72
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized (Gain) Loss Arising During Period, Tax	8		20		'
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	0		0		'
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Tax	1		2		'
Other Comprehensive Income (Loss), Reclassification Adjustment on Pension Curtailment Gain, Tax	9		0		'
Other Comprehensive Income (Loss), Reclassification Adjustment, Acquisition, Net Tax Expense	$20		$0		'
[1]	Amount related to the reclassification of mark-to-market loss on cash flow hedging activities, net and was recorded in Interest Charges in our consolidated statements of operations.
[2]	Amounts are associated with our defined benefit pension and other postretirement benefit plans and are included in the computation of net periodic pension cost. Please read Note 6—Retirement Benefits for further discussion.
[3]	Amount related to the EEI curtailment gain on pension and postretirement benefit plans and was recorded in Other operations and maintenance in our consolidated statements of operations. Please read Note 6—Retirement Benefits for further discussion.
[4]	Amount related to the transfer of certain defined benefit pension and other postretirement benefit plans as a part of the AER Acquisition. Please read Note 6—Retirement Benefits for further discussion.

Selected_Quarterly_Information2

Selected Quarterly Information (Unaudited) (Summary Of Selected Quarterly Information) (Details) (USD $)	3 Months Ended																12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Selected Quarterly Financial Information [Abstract]	'		'		'		'		'		'		'		'		'	'	'
Operating Revenues	$155		$275		$187		$187		$202		$218		$194		$194		$804	$808	$1,066
Operating Income (Loss)	16	[1]	0	[1]	-25	[1]	-204	[1]	-60	[1]	34	[1]	-4	[1]	13	[1]	-213	-17	139
Net Income (Loss)	-33		-5		-22		-129		-42		11		-6		-3		-189	-40	45
Net Income (Loss) Attributable to Illinois Power Generating Company	-32		-5		-22		-129		-41		13		-4		-1		-188	-33	44
Impairment and other charges	'		'		'		'		$70		'		'		'		$199	$70	$35
[1]	Includes pretax “Impairment and other charges” of $199 million and $70 million recorded during the years ended December 31, 2013 and 2012, respectively. Please read Note 11—Impairment and Other Charges for further discussion.