Illinois Power Generating 10-K 29 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 18, 2016	Jun. 30, 2015
Entity [Abstract]
Entity Registrant Name	ILLINOIS POWER GENERATING COMPANY
Entity Central Index Key	1,135,361
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
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	No
Entity Public Float			$ 0

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash	$ 61	$ 126
Accounts receivable, affiliates	54	88
Accounts receivable	8	14
Inventory	133	82
Deferred income taxes	0	5
Prepayments and other current assets	7	11
Total Current Assets	263	326
Property, Plant and Equipment	1,750	3,016
Less: Accumulated depreciation and amortization	(813)	(1,145)
Property, Plant and Equipment, Net	937	1,871
Other Assets	30	24
Total Assets	1,230	2,221
Current Liabilities
Accounts payable	26	39
Accounts payable, affiliates	18	13
Taxes accrued	10	11
Accrued interest	10	10
Accrued liabilities and other current liabilities	9	10
Total Current Liabilities	73	83
Long-term debt	824	824
Other Liabilities
Deferred income taxes, net	119	498
Asset retirement obligations	49	90
Other long-term liabilities	24	30
Total Liabilities	$ 1,089	$ 1,525
Commitments and Contingencies (Note 13)
Stockholder’s Equity
Common stock, no par value, 10,000 shares authorized 2,000 shares outstanding	$ 0	$ 0
Additional paid-in capital	542	540
Accumulated other comprehensive loss, net of tax	(10)	(16)
Retained earnings	(396)	166
Total Illinois Power Generating Company Stockholder’s Equity	136	690
Noncontrolling interest	5	6
Total Equity	141	696
Total Liabilities and Equity	$ 1,230	$ 2,221

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common stock, no par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized	10,000	10,000
Common stock, shares outstanding	2,000	2,000

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Revenues	$ 534	$ 648	$ 811
Cost of sales, excluding depreciation expense	(333)	(447)	(607)
Gross margin	201	201	204
Operating and maintenance expense	(162)	(158)	(138)
Impairment	(855)	0	(199)
Depreciation and amortization expense	(86)	(100)	(80)
Operating loss	(902)	(57)	(213)
Interest expense	(39)	(40)	(42)
Other income and expense, net	0	0	1
Loss before income taxes	(941)	(97)	(254)
Income tax benefit	378	49	65
Net loss	(563)	(48)	(189)
Less: Net income (loss) attributable to noncontrolling interest	(1)	2	(1)
Net loss attributable to Illinois Power Generating Company	$ (562)	$ (50)	$ (188)

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net loss		$ (563)	$ (48)	$ (189)
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) due to pension plan remeasurement (net of tax benefit (expense) of $3, ($10) and ($26), respectively)		6	(11)	15
AER Acquisition (net of tax expense of zero, zero and $20 respectively)	[1]	0	0	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 of tax benefit of zero, zero and zero, respectively)	[2]	1	1	1
Settlement loss on pension plan (net of tax benefit of zero, zero and zero, respectively)		0	2	0
Reclassification of curtailment gain included in net loss (net of tax benefit of zero, zero and $10, respectively)		0	0	(16)
Amortization of unrecognized prior service credit and actuarial gain (loss) (net of tax expense of zero, $1 and $2, respectively)	[3]	(1)	0	1
Other comprehensive income (loss), net of tax		6	(8)	29
Comprehensive loss		(557)	(56)	(160)
Less: Comprehensive loss attributable to noncontrolling interest		0	(1)	(1)
Total comprehensive loss attributable to Illinois Power Generating Company		$ (557)	$ (55)	$ (159)
[1]	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 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.
[2]	Amount related to the reclassification of mark-to-market loss on cash flow hedging activities, net and was recorded in Interest expense on our consolidated statements of operations. Please read Note 4—Derivative Financial Instruments for further discussion.
[3]	Amounts are associated with our defined benefit pension and other post-retirement benefit plans and are included in the computation of net periodic benefit cost (gain). Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.

Consolidated Statements of Com6

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Tax benefit (expense) of actuarial gain (loss) and plan amendments		$ 3	$ (10)	$ (26)
Tax expense of the AER Acquisition	[1]	0	0	20
Tax of reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges, net	[2]	0	0	0
Tax of settlement loss on pension plan	[3]	0	0	0
Reclassification of curtailment gain included in net loss, tax benefit		0	0	10
Tax expense of amortization of unrecognized prior service credit and actuarial gain (loss)		$ 0	$ 1	$ 2
[1]	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 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.
[2]	Amount related to the reclassification of mark-to-market loss on cash flow hedging activities, net and was recorded in Interest expense on our consolidated statements of operations. Please read Note 4—Derivative Financial Instruments for further discussion.
[3]	Amount related to the settlement loss on the EEI pension plan and is included in the computation of total benefit cost (gain). Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (563)	$ (48)	$ (189)
Adjustments to reconcile net loss to net cash flows from operating activities:
Impairment	855	0	199
Curtailment gain on pension and postretirement benefits	0	0	(26)
Risk management activities	0	0	(7)
Depreciation and amortization expense	86	100	80
Deferred income taxes and investment tax credits, net	(378)	(48)	(1)
Other	10	6	0
Changes in working capital:
Accounts receivable, net	40	(27)	6
Inventory	(51)	(1)	15
Accounts payable and accrued liabilities	(7)	8	(14)
Other	1	(6)	(12)
Net cash provided by (used in) operating activities	(7)	(16)	51
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(58)	(48)	(55)
Proceeds from sales of properties	0		138
Money pool advances, net	0		27
Net cash provided by (used in) investing activities	(58)	(48)	110
CASH FLOWS FROM FINANCING ACTIVITIES:
Capital contribution from parent	0	0	4
Net cash provided by financing activities	0	0	4
Net increase (decrease) in cash	(65)	(64)	165
Cash, beginning of period	126	190	25
Cash, end of period	$ 61	$ 126	$ 190

Consolidated Statements of Chan

Consolidated Statements of Changes in Stockholders' Equity - USD ($) $ in Millions	Total	Common Stock	Additional Paid-In Capital	Retained Earnings	AOCI (Loss)	Total Controlling Interests	Non-controlling Interest	Total
Stockholders' Equity beginning of the period at Dec. 31, 2012		$ 0	$ 656	$ 404	$ (40)	$ 1,020
Noncontrolling Interest, beginning of the period at Dec. 31, 2012							$ 8
Total Equity, beginning of the period at Dec. 31, 2012								$ 1,028
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Capital contribution from parent	$ 4	0	76	0	0	76	0	76
Adjustments to tax NOLs and other attributes from acquisition	(178)	0	(178)	0	0	(178)	0	(178)
Other paid-in capital		0	(3)	0	0	(3)	0	(3)
Net loss, attributable to parent	(188)	0	0	(188)	0	(188)
Net income (loss), attributable to noncontrolling interest	(1)						(1)
Net loss	(189)							(189)
Other comprehensive loss, net of tax, attributable to parent	1	0	0	0	29	29
Other comprehensive loss, net of tax, attributable to noncontrolling interest							0
Other comprehensive loss, net of tax	29							29
Stockholders' Equity end of the period at Dec. 31, 2013		0	551	216	(11)	756
Noncontrolling Interest, end of the period at Dec. 31, 2013							7
Total Equity, end of the period at Dec. 31, 2013								763
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Capital contribution from parent	0
Adjustments to tax NOLs and other attributes from acquisition	(6)	0	(6)	0	0	(6)	0	(6)
Amounts due to parent under tax sharing agreement		0	(5)	0	0	(5)	0	(5)
Net loss, attributable to parent	(50)	0	0	(50)	0	(50)
Net income (loss), attributable to noncontrolling interest	2						2
Net loss	(48)							(48)
Other comprehensive loss, net of tax, attributable to parent	(5)	0	0	0	(5)	(5)
Other comprehensive loss, net of tax, attributable to noncontrolling interest							(3)
Other comprehensive loss, net of tax	(8)							(8)
Stockholders' Equity end of the period at Dec. 31, 2014	690	0	540	166	(16)	690
Noncontrolling Interest, end of the period at Dec. 31, 2014	6						6
Total Equity, end of the period at Dec. 31, 2014	696							696
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Capital contribution from parent	0
Amounts due to parent under tax sharing agreement		0	2	0	0	2	0	2
Net loss, attributable to parent	(562)	0	0	(562)	0	(561)
Net income (loss), attributable to noncontrolling interest	(1)						(1)
Net loss	(563)							(563)
Other comprehensive loss, net of tax, attributable to parent	6	0	0	0	6	6
Other comprehensive loss, net of tax, attributable to noncontrolling interest							0
Other comprehensive loss, net of tax	6							6
Stockholders' Equity end of the period at Dec. 31, 2015	136	$ 0	$ 542	$ (396)	$ (10)	$ 137
Noncontrolling Interest, end of the period at Dec. 31, 2015	5						$ 5
Total Equity, end of the period at Dec. 31, 2015	$ 141							$ 141

Organization and Operations

Organization and Operations	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Operations	Note 1—Organization and Operations We are an electric generation subsidiary of Illinois Power Resources, LLC (“IPR”), which is an indirect wholly-owned subsidiary of Dynegy Inc. (“Dynegy”). Unless the context indicates otherwise, throughout this report, the terms “Genco,” “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Illinois Power Generating Company and its direct and indirect subsidiaries. We are headquartered in Houston, Texas and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois and have an 80 percent ownership interest in Electric Energy, Inc. (“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. On December 2, 2013 (the “Acquisition Date”), we were acquired indirectly by IPH, an indirect wholly-owned subsidiary of Dynegy. On the Acquisition Date, pursuant to the terms of the definitive agreement dated as of March 14, 2013 and as amended on the Acquisition Date (the “AER Transaction Agreement”) by and between IPH and Ameren Corporation (“Ameren”), IPH completed its acquisition from Ameren of 100 percent of the equity interests of New Ameren Energy Resources, LLC (“New AER”) and its subsidiaries (the “AER Acquisition”). “Push-down accounting” was not applied as a result of the AER Acquisition, which would require the adjustment of the assets and liabilities to fair value recognized by Dynegy to be shown in our consolidated financial statements. We are organized into a ring-fenced group in order to maintain corporate separateness from Dynegy and its other legal entities. 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.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2—Summary of Significant Accounting Policies Principles of Consolidation and Basis of Presentation. The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries. Intercompany accounts and transactions have been eliminated. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. Certain prior period amounts in our consolidated statements of operations have been reclassified to conform to current year presentation. Accounting policies for all of our operations are in accordance with accounting principles generally accepted in the United States of America. Noncontrolling Interest. Noncontrolling interest is comprised of the 20 percent of EEI we do not own. This noncontrolling interest is classified as a component of equity separate from our equity in our consolidated balance sheets. Use of Estimates. The preparation of consolidated financial statements in conformity with Generally Accepted Accounting Principles (“GAAP”) requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing tangible assets for possible impairment, (iii) estimating the useful lives of our assets and Asset Retirement Obligations (“AROs”), (iv) assessing future tax exposure and the realization of deferred tax assets, (v) determining amounts to accrue for contingencies, guarantees and indemnifications and (vi) estimating various factors used to value our pension assets and liabilities. Actual results could differ materially from our estimates. Inventory. Our commodity and materials and supplies inventories are carried at the lower of weighted average cost and net realizable value (“NRV”). Property, Plant and Equipment. Property, plant and equipment, which consist principally of power generating facilities, including capitalized interest, is generally recorded at historical cost. 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. Depreciation is provided using the straight-line method over the estimated economic service lives of the assets, ranging from 2 to 30 years. The estimated economic service lives of our asset groups are as follows: Asset Group Range of Years Power generation 3 to 30 Buildings and improvements 2 to 30 Office and other equipment 3 to 20 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 3—Impairments for further discussion. Asset Retirement Obligations. We record the present value of our legal obligations to retire tangible, long-lived assets on our balance sheets as liabilities when the liability is incurred. Our AROs relate to activities such as Coal Combustion Residuals (“CCR”) surface impoundment and landfill closure, dismantlement of power generation facilities, future removal of asbestos containing material from certain power generation facilities, closure and post-closure costs, environmental testing, remediation, monitoring and land obligations. In subsequent periods, we make upward or downward revisions to AROs in accordance with GAAP. 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. Accretion expense is included in Operating and maintenance expense on our consolidated statements of operations. The following table provides a reconciliation of the beginning and ending carrying amounts of AROs for the year ended December 31, 2015: (amounts in millions) Balance at December 31, 2013 $ 43 Accretion expense 3 Revision of previous estimate (1) 44 Balance at December 31, 2014 90 Accretion expense 9 Revision of previous estimate (2) (50 ) Balance at December 31, 2015 $ 49 __________________________________________ (1) During 2014, we revised our ARO upward by $44 million based on observed trends in Illinois primarily related to CCR surface impoundment closures, groundwater monitoring and updated cost estimates for asbestos in accordance with the standards used in the industry. (2) During 2015, we revised our ARO downward by $50 million based on management’s review and assessment of CCR compliance timing and site specific analysis. Contingencies, Commitments, Guarantees and Indemnifications. We are involved in numerous lawsuits, claims, proceedings and tax-related audits in the normal course of our operations. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies on an ongoing basis to ensure that we have appropriate reserves recorded on our consolidated balance sheets. These reserves are based on estimates and judgments made by management with respect to the likely outcome of these matters, including any applicable insurance coverage for litigation matters, and are adjusted as circumstances warrant. Liabilities for environmental contingencies are recorded when an environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability. 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 PSAs with Illinois Power Marketing Company (“IPM”). Revenue is recognized when the product or service is delivered to a customer, unless they meet the definition of a derivative. Fair Value Measurements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Our estimate of fair value reflects the impact of credit risk. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs are classified as readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the classification of the inputs used to calculate the fair value of a transaction. The inputs used to measure fair value have been placed in a hierarchy based on priority. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: • Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities. • Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using industry-standards models or other valuation methodologies, in which substantially all assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter forwards, options and swaps. • Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to our needs. At each balance sheet date, we perform an analysis of all instruments and include in Level 3 all of those whose fair value is based on significant unobservable inputs. The determination of fair value incorporates various factors. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities. Valuation adjustments are generally based on capital market implied ratings evidence when assessing the credit standing of our counterparties and when applicable, adjusted based on management’s estimates of assumptions market participants would use in determining fair value. 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 entered into a tax sharing agreement effective December 2, 2013, which was amended and restated as of December 31, 2014. Under the terms of the new tax sharing agreement, we recognize taxes based on a separate company income tax return basis and settle taxes with Dynegy at the discretion of either Dynegy’s or Genco’s management, as defined in the agreement. As a result of the AER Acquisition, we are under IRC Section 382, and are subject to a limitation in the amount of net operating losses (“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 . Please read Note 12—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. Employee Separation and Other Charges. Employee separation programs were initiated as a result of the AER Acquisition to reduce positions under terms and benefits consistent with our former parent Ameren’s standard management separation program. We recorded pretax charges related to these programs of less than $1 million , and $3 million for the years ended December 31, 2014 and 2013, respectively. These charges were recorded in Operating and maintenance expense on the consolidated statements of operations. There were no charges incurred in 2015, and we do not expect to pay out severance benefits in 2016. Accounting Standards Adopted Income Taxes. In November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-17-Income Taxes (Topic 740). The amendment in this ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The guidance in this ASU is effective for public entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period. The ASU may be applied prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We adopted ASU 2015-17 as of December 31, 2015 and applied the guidance prospectively with no change to prior period amounts disclosed in our consolidated balance sheets and related notes to the consolidated financial statements. Please read Note 12—Income Taxes for further details. Derivatives. In August 2015, the FASB issued Accounting Standards Update ASU 2015-13-Derivatives and Hedging (Topic 815). The amendments in this ASU specify that the use of locational marginal pricing by an ISO does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis and, therefore, does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. If the physical delivery criterion is met, along with all of the other criteria of the normal purchases and normal sales scope exception, an entity may elect to designate that contract as a normal purchase or normal sale. The amendments in this ASU are effective upon issuance and should be applied prospectively. The adoption of this ASU did not have a material impact on our consolidated financial statements. Inventory. In July 2015, the FASB issued ASU 2015-11-Inventory (Topic 330). The amendments in this ASU require that inventory is measured at the lower of cost and NRV, with the latter defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This ASU eliminates the need to determine market or replacement cost and evaluate whether it is above the ceiling at NRV or below the floor (NRV less a normal profit margin). The guidance in this ASU is effective prospectively for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted ASU 2015-11 as of July 1, 2015. The adoption of this ASU did not have a material impact on our consolidated financial statements. Retirement Benefits. In April 2015, the FASB issued ASU 2015-04-Compensation-Retirement Benefits (Topic 715). For an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan or post retirement plan assets and obligations, the amendments in this Update provide a practical expedient that permits the entity to remeasure the plan assets and obligations using the month-end that is closest to the date of the significant event. The month-end remeasurement of defined benefit plan assets and obligations that is closest to the date of the significant event should be adjusted for any effects of the significant event that may or may not be captured in the month-end measurement. An entity is required to disclose the accounting policy election and the date used to measure defined benefit plan assets and obligations in accordance with the amendments in this Update. The amendments in this Update are effective for public business entities for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption allowed. The amendments in this Update should be applied prospectively. We adopted the guidance in this ASU on July 1, 2015. The adoption of this ASU did not have a material impact on our consolidated financial statements. Reporting Discontinued Operations and Asset Disposals. In April 2014, the FASB issued ASU 2014-08-Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosure of Disposals of Components of an Entity. The amendments in this ASU change the requirements for reporting discontinued operations in Subtopic 205-20. An entity is required to report within discontinued operations on the statement of operations the results of a component or group of components of an entity if the disposal represents a strategic shift that has, or will have, a major effect on an entity’s operations and financial results. Additionally, the associated assets and liabilities are required to be presented separately from other assets and liabilities on the balance sheet for all comparative periods. The ASU includes updated guidance regarding what meets the definition of a component of an entity. The new financial statement presentation provisions relating to this ASU are prospective and effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. We adopted the guidance in this ASU on January 1, 2015. The adoption of this ASU did not have a material impact on our financial statements or disclosures. Accounting Standards Not Yet Adopted Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The amendments in this ASU will mainly require lessees to recognize lease assets and lease liabilities, for those leases classified as operating leases under GAAP, in their balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our consolidated financial statements. Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. In August 2015, the FASB issued ASU 2015-15-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU further clarify the guidance provided in ASU 2015-03 to include the presentation of debt issuance costs in relation to line-of-credit arrangements. The amendments state these costs may be presented as an asset and subsequently amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance in these ASUs is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The adoption of these ASUs should be applied on a retrospective basis, affecting all balance sheet periods presented. We do not anticipate the adoption of these ASUs will have a material impact on our consolidated balance sheets. Extraordinary and Unusual Items. In January 2015, the FASB issued ASU 2015-01-Income Statement-Extraordinary and Unusual Items (Subtopic 225-20). The amendments in this ASU eliminate from GAAP the concept of extraordinary items and will no longer require separate classification of these items within the statement of operations. Presentation and disclosure guidance for items that are unusual in nature or occur infrequently will be retained and will be expanded to include items that are both unusual in nature and infrequently occurring. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Reporting entities may elect to apply the amendments prospectively only, or retrospectively for all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. We do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements. Going Concern. In August 2014, the FASB issued ASU 2014-15-Presentation of Financial Statements - Going Concern (Subtopic 205-40). The amendments in this ASU requires management, in connection with preparing financial statements for each annual and interim reporting period, to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). Currently, there is no guidance in GAAP about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern or to provide related footnote disclosures. The amendments in this ASU provide that guidance. In doing so, the amendments should reduce diversity in the timing and content of footnote disclosures. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We currently do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements. Revenue from Contracts with Customers. In May 2014, the FASB and International Accounting Standards Board jointly issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU was further updated through the issuance of ASU 2015-14 in August 2015. The amendments in this ASU develop a common revenue standard for GAAP and International Financial Reporting Standards by removing inconsistencies and weaknesses in revenue requirements, providing a more robust framework for addressing revenue issues, improving comparability of revenue recognition practices, providing more useful information to users of financial statements and simplifying the preparation of financial statements. The guidance in this ASU is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are currently assessing this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements.

Impairments

Impairments	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment Impairment or Disposal [Abstract]
Impairments	Note 3—Impairments 2015 Coffeen Impairment During the third quarter of 2015, several environmental regulations were adopted which will have an impact on our coal-fired power generation facilities. As a result of these regulations, we performed a strategic review of our assets which incorporated the costs of these regulations, and incorporated a reduced long-term market outlook, caused by MISO’s poorly designed wholesale capacity market. The analysis indicated that the book value of the Coffeen facility was not recoverable, requiring the facility to be impaired. We conducted a held and used discounted cash flow model of the facility to determine its fair value. For the model, gross margin was based on publicly available forward market quotes for the first two years and internally developed prices thereafter, operations and maintenance expenses and capital expenditures were based on current forecasts and used a plant-specific discount rate of approximately 15% . The model resulted in a fair value of zero for the plant, requiring us to record an impairment charge of $855 million during the third quarter of 2015. 2013 Gas-fired Facilities Impairment In October 2013, we divested our Elgin, Gibson City and Grand Tower gas-fired facilities (the “Gas-Fired Facilities”) to Ameren Energy Medina Valley Cogen LLC (“Medina Valley”), an affiliate of Ameren Energy Resources Company, LLC (“AER”) that IPH did not acquire in the AER Acquisition, under a put option agreement that was assumed by Medina Valley and exercised by us in March 2013 (the “Put Option”). We recorded a pretax charge to earnings of $199 million for 2013, to reflect the impairment of the Gas-Fired Facilities under the 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 during the year ended December 31, 2012. The impairment charges were recorded in Impairment on our consolidated statements of operations for the year ended December 31, 2013 . The impairment charges did not result in a violation of our debt covenants or counterparty agreements. 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. 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.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instrument Detail [Abstract]
Derivative Financial Instruments	Note 4—Derivative Financial Instruments There are no derivative instruments as of December 31, 2015 and 2014 . Impact of Derivatives on the Consolidated Statements of Operations The cumulative amount of pretax net losses on interest rate derivative instruments in accumulated other comprehensive income (“AOCI”) was $4 million , $5 million and $6 million as of December 31, 2015 , 2014 and 2013 , respectively. These interest rate swaps were executed in 2007 and designated as a cash flow 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, $1.4 million of which was amortized in 2015 . Financial Instruments Not Designated as Hedges. There was no material impact of mark-to-market gains (losses) on our consolidated statements of operations for the years ended December 31, 2015 and 2014. Revenues on our consolidated statements of operations for the year ended December 31, 2013 included mark-to-market gains of $7 million related to commodity derivatives.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 5—Fair Value Measurements Non-recurring Measurements. We recorded impairment charges in our 2015 and 2013 statements of operations of $855 million and $199 million , respectively, related to long-lived assets using fair value techniques. Please read Note 3—Impairments for further details. The valuation methods used to determine the impairment charges were classified as Level 3 within the fair value hierarchy levels. Fair Value of Financial Instruments. We have determined estimated fair value amounts using available market information and selected valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies could have a material effect on the estimated fair value amounts. The carrying values of financial assets and liabilities (cash, accounts receivable, restricted cash and accounts payable) not presented in the table below approximate fair values due to the short-term maturities of these instruments. Unless otherwise noted, the fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes as of December 31, 2015 and 2014 , respectively. All fair values presented below are classified within Level 2 of the fair value hierarchy. December 31, 2015 December 31, 2014 (amounts in millions) Carrying Amount Fair Value Carrying Amount Fair Value 7.00% Senior Notes Series H, due 2018 $ 300 $ 204 $ 300 $ 264 6.30% Senior Notes Series I, due 2020 $ 250 $ 148 $ 250 $ 208 7.95% Senior Notes Series F, due 2032 (1) $ 274 $ 162 $ 274 $ 241 __________________________________________ (1) Carrying amount includes unamortized discount of $1 million as of December 31, 2015 and 2014 . Please read Note 10—Debt for further discussion.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Note 6—Accumulated Other Comprehensive Income (Loss) Changes in accumulated other comprehensive income (loss), net of tax, by component are as follows: Year Ended December 31, (amounts in millions) 2015 2014 2013 Beginning of period $ (16 ) $ (11 ) $ (40 ) Other comprehensive income (loss) before reclassifications: Actuarial gain (loss) and plan amendments (net of tax benefit (expense) of $3, $4, and ($8), respectively) 6 (8 ) 12 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, zero and zero, respectively) (1) 1 1 1 Settlement loss on pension plan (net of tax benefit of zero, zero and zero, respectively) (2) — 2 — Amortization of unrecognized prior service credit and actuarial loss (net of tax expense of zero, zero, and $1, respectively) (3) (1 ) — 1 Reclassification of curtailment gain included in net loss (net of tax benefit of zero, zero, and $9, respectively) (4) — — (13 ) Net current period other comprehensive income (loss), net of tax 6 (5 ) 1 AER Acquisition (net of tax expense of zero, zero, and $20, respectively) (5) — — 28 End of period $ (10 ) $ (16 ) $ (11 ) __________________________________________ (1) Amount related to the reclassification of mark-to-market loss on cash flow hedging activities, net and was recorded in Interest expense on our consolidated statements of operations. Please read Note 4—Derivative Financial Instruments for further discussion. (2) Amount related to the settlement loss on the EEI pension plan and is included in the computation of total benefit cost (gain). Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion. (3) Amounts are associated with our defined benefit pension and other post-retirement benefit plans and are included in the computation of net periodic benefit cost (gain). Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion. (4) Amount related to the EEI curtailment gain on pension and postretirement benefit plans and was recorded in Operating and maintenance expense in our consolidated statements of operations. Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion. (5) 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 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.

Cash Flow Information

Cash Flow Information	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Cash Flow Information	Note 7—Cash Flow Information Following are supplemental disclosures of cash flow and non-cash investing and financing information: Year Ended December 31, (amounts in millions) 2015 2014 2013 Interest paid (net of amount capitalized) $ 37 $ 39 $ 41 Income taxes, net $ — $ — $ (65 ) Other non-cash investing and financing activity: Non-cash capital expenditures (1) $ — $ 3 $ 3 Capital contributions from parent $ — $ — $ 72 __________________________________________ (1) These expenditures are primarily for changes in our accruals of capital expenditures for all years presented.

Inventory

Inventory	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Inventory	Note 8—Inventory A summary of our inventories is as follows: December 31, (amounts in millions) 2015 2014 Materials and supplies $ 30 $ 30 Coal 102 51 Fuel oil 1 1 Total $ 133 $ 82

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Note 9—Property, Plant and Equipment A summary of our property, plant and equipment is as follows: December 31, (amounts in millions) 2015 2014 Power generation $ 1,511 $ 2,710 Building and improvements 212 276 Office and other equipment 27 30 Property, plant and equipment $ 1,750 $ 3,016 Less: Accumulated depreciation and amortization (813 ) (1,145 ) Property, plant and equipment, net $ 937 $ 1,871 During the third quarter of 2015, we recorded an impairment charge to our Coffeen facility of $855 million . For more information see Note 3—Impairments . The following table summarizes total interest costs incurred and interest capitalized related to costs of construction projects in process: Year Ended December 31, (amounts in millions) 2015 2014 2013 Total interest costs incurred $ 59 $ 59 $ 60 Capitalized interest $ 22 $ 20 $ 18

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
Debt	Note 10—Debt A summary of our long-term debt is as follows: December 31, (amounts in millions) 2015 2014 Unsecured notes: 7.00% Senior Notes Series H, due 2018 $ 300 $ 300 6.30% Senior Notes Series I, due 2020 250 250 7.95% Senior Notes Series F, due 2032 275 275 825 825 Unamortized discount (1 ) (1 ) Total long-term debt $ 824 $ 824 Aggregate maturities of the principal amounts of all long-term indebtedness, excluding unamortized discounts, as of December 31, 2015 are as follows: 2016 — zero , 2017 — zero , 2018 — $300 million , 2019 — zero , 2020 — $250 million and thereafter — $275 million . Indenture Provisions and Other Covenants Certain of our financial obligations and all of our senior notes include provisions which, if not met, could require early payment, additional collateral support or similar actions. The trigger events include the violation of covenants, defaults on scheduled principal or interest payments, including any indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions, insolvency events and acceleration of other financial obligations. At December 31, 2015 , we were in compliance with the provisions and covenants contained within our indenture. Our indenture also 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 (1) ≥1.75 Additional indebtedness interest coverage ratio (2) ≥2.50 Additional indebtedness debt-to-capital ratio (2) ≤60% _______________________________________ (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. As of December 31, 2015, we did not meet our debt incurrence-related ratios and therefore we are prohibited from incurring additional third-party indebtedness. Our required ratios 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. 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 December 31, 2015 calculations, our interest coverage ratios are less than the minimum ratios required to pay dividends . As a result, we were restricted from paying dividends as of December 31, 2015 . 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.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Note 11—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 power purchases and sales, services received or rendered, and borrowings and lendings. Below are the material related party agreements. The following table summarizes the affiliate accounts receivable and payable on our consolidated balance sheets. December 31, 2015 December 31, 2014 (amounts in millions) Accounts Receivable, Affiliates Accounts Payable, Affiliates Accounts Receivable, Affiliates Accounts Payable, Affiliates Power supply agreements $ 54 $ — $ 88 $ — Services agreement — 5 — 1 Tax sharing agreement — 3 — 5 Other (1) — 10 — 7 Total $ 54 $ 18 $ 88 $ 13 __________________________________________ (1) As of December 31, 2015 , approximately $10 million of the accounts payable, affiliate balance is comprised of reimbursable employee benefits paid by a Dynegy subsidiary on behalf of Genco. The following table presents the impact of related party transactions on our consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013. Year Ended December 31, (amounts in millions) Income Statement Line Item 2015 2014 2013 Power supply agreements Revenues $ 530 $ 646 $ 709 Services provided to AER affiliates Revenues $ — $ — $ 6 Ameren Missouri gas transportation agreement Cost of sales $ — $ — $ 1 EEI power supply agreement Cost of sales $ — $ — $ 66 Services agreement Operating and maintenance expense $ 34 $ 43 $ 13 Power Supply Agreements Genco has a PSA with Illinois Power Marketing Company (“IPM”), a subsidiary of IPR, whereby IPM purchases all of the capacity and energy available from Genco’s generation fleet. IPM entered into a similar PSA with Illinois Power Resources Generating, LLC (“IPRG”). Under the PSAs, IPM revenues are allocated between Genco and IPRG based on reimbursable expenses and generation of each entity. The reimbursable expenses used in the calculation of revenues allocated under the Genco and IPRG PSAs include operation costs in addition to depreciation and interest on debt. 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. EEI has a PSA with IPM, whereby IPM purchases all of the capacity and energy available from EEI’s generation fleet. With limited exceptions, the price that IPM pays for capacity is the MISO Local Resources Zone 4 clearing price. IPM pays spot market prices for the associated energy. In addition, EEI will at times purchase energy from IPM to fulfill obligations to a non-affiliated party. The PSA will continue through December 31, 2022. Either party to the PSA may elect to terminate the PSA by providing the other party with no less than six months advance written notice. Collateral Agreement Genco has a collateral agreement with IPM pursuant to which IPM may require Genco to provide collateral to IPM to secure obligations of IPM applicable to Genco’s assets. The initial collateral limit for Genco is $15 million and IPM can demand an additional $7.5 million for a total limit not to exceed $22.5 million . There have been no amounts provided under this agreement to date. Services Agreements Dynegy and certain of its subsidiaries (collectively, the “Providers”) provide 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 Services 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 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 operated as an unaffiliated entity. Effective December 31, 2015, we amended the Services Agreement to provide payments to Dynegy for services incurred which may be deferred based on the liquidity of certain of IPH’s subsidiaries as of the current month’s end. Any deferred payments, and associated interest, will be reflected as an affiliate payable to be settled at the discretion of Dynegy or us. The amendment will be in place through 2016 and will be evaluated for extension in the fourth quarter of 2016. Tax Sharing Agreement 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. Genco and Dynegy entered into a tax sharing agreement on December 2, 2013 that provides that we recognize taxes based on a separate company income tax return basis, as defined in the agreement. The tax sharing arrangement was amended as of December 31, 2014 and provides that accumulated taxes payable to Dynegy, and any associated interest, be settled at the discretion of Dynegy or us.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Note 12—Income Taxes Income Tax Benefit. We are subject to U.S. federal and state income taxes on our operations. Our loss before income taxes was $941 million , $97 million and $254 million for the years ended December 31, 2015, 2014 and 2013, respectively. 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, 2015 2014 2013 Statutory federal income tax rate: 35 % 35 % 35 % Increases (decreases) from: State tax 5 6 6 Acquisition adjustment (1) — 9 (15 ) Effective income tax rate 40 % 50 % 26 % _________________________________________ (1) Acquisition adjustments relating to the impacts of the change in ownership under IRC Section 382 and other tax attribute reductions. The following table presents the components of income tax benefit: Year Ended December 31, (amounts in millions) 2015 2014 2013 Current taxes: Federal $ — $ 1 $ 50 State — — 14 Deferred taxes: Federal 305 39 (6 ) State 73 9 6 Deferred investment tax credits, amortization — — 1 Total income tax benefit $ 378 $ 49 $ 65 The Illinois corporate income tax rate decreased from 9.5 percent to 7.75 percent in 2015, and it is scheduled to return to 7.3 percent in 2025. The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences: December 31, (amounts in millions) 2015 2014 Accumulated deferred income taxes, net liability (asset): Plant related $ 167 $ 551 Deferred employee benefit costs (1 ) (6 ) ARO (15 ) (36 ) NOLs (25 ) (7 ) Other (7 ) (9 ) Total net accumulated deferred income tax liabilities $ 119 $ 493 Uncertain Tax Positions. A reconciliation of the change in the unrecognized tax benefit balance is as follows: Year Ended December 31, (amounts in millions) 2015 2014 2013 Unrecognized tax benefits - beginning of year $ — $ — $ 6 Increases based on tax positions prior to current year — — 2 Decreases based on tax positions prior to current year — — (3 ) Decreases based on tax positions related to current year — — (1 ) Adjustment of balance due to change in ownership — — (3 ) Decreases related to the lapse of statute of limitations — — (1 ) Unrecognized tax benefits - end of year $ — $ — $ — Total unrecognized tax benefits (detriments) that, if recognized, would affect the effective tax rates $ — $ — $ — Interest charges (income) and penalties accrued on tax liabilities on a pretax basis are recognized as interest charges (income) or miscellaneous expense, respectively, in our consolidated statements of operations. A reconciliation of the change in the liability for interest on unrecognized tax benefits is as follows: Year Ended December 31, (amounts in millions) 2015 2014 2013 Liability for interest - beginning of year $ — $ — $ 1 Adjustment of balance due to change in ownership — — (1 ) Liability for interest - end of year $ — $ — $ — As of December 31, 2015, 2014 and 2013, we accrued no amount for penalties with respect to unrecognized tax benefits. Upon the closing of the AER Acquisition, we are included in the consolidated federal and state tax returns of Dynegy. Genco and Dynegy entered into a tax sharing agreement effective December 2, 2013, which was amended and restated as of December 31, 2014. Under the terms of the new tax sharing agreement, we recognize taxes based on a separate company income tax return basis and settle taxes with Dynegy at the discretion of either Dynegy’s or Genco’s management, as defined in the agreement. Genco’s tax payable of $3 million and $5 million for the years ended 2015 and 2014, respectively, has been recorded at the total amount due to Dynegy under its tax sharing agreement for all of its subsidiaries in accordance with ASC 740. The changes in Genco’s tax payable resulted in positive adjustment of $2 million and charge of $5 million to equity for the years ended 2015 and 2014, respectively. As a result of the AER Acquisition, we are under IRC Section 382 and are subject to a limitation in the amount of NOLs that could be used in any one year following the 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 basis, totaling $425 million . The adjustments to our NOLs and tax attributes resulted in a charge to paid-in capital at the Acquisition Date of $6 million and $178 million for the years ended December 31, 2014 and 2013, respectively. We also increased our income tax benefit by $9 million for the year ended December 31, 2014 and reduced our income tax benefit by $39 million for the year ended December 31, 2013. As of December 31, 2015 , we had approximately $62 million of state NOLs and $62 million federal NOLs on a separate return basis that expire in 2034 and 2035. We are currently under federal audit for the 2014 tax period. 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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 13—Commitments and Contingencies Legal Proceedings Set forth below is a summary of our material ongoing legal proceedings. We record accruals for estimated losses from contingencies when available information indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, we disclose matters for which management believes a material loss is reasonably possible. In all instances, management has assessed the matters below based on current information and made judgments concerning their potential outcome, giving consideration to the nature of the claim, the amount, if any, and nature of damages sought and the probability of success. Management regularly reviews all new information with respect to such contingencies and adjusts its assessments and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties including unfavorable rulings or developments, it is possible that the ultimate resolution of our legal proceedings could involve amounts that are different from our currently recorded accruals and that such differences could be material. In addition to the matters discussed below, we are party to other routine proceedings arising in the ordinary course of business. Any accruals or estimated losses related to these matters are not material. In management’s judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations or cash flows. Contingencies MISO 2015-2016 Planning Resource Auction. In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (“PRA”) conducted by MISO. The Newton, Coffeen and Joppa facilities were offered into Zone 4 in the 2015-2016 PRA. The complainants, Public Citizen, Inc., the Illinois Attorney General, and Southwestern Electric Cooperative, In c., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. Dynegy disputes the allegations and will defend its actions vigorously. Dynegy filed its Answer to these complaints. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint. On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA (the “Order”). The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule or regulation. Further, FERC held a Staff-led technical conference on October 20, 2015 to obtain further information concerning potential changes to the MISO PRA structure going forward, including on proposals made by complainants. The technical conference did not address the ongoing Office of Enforcement investigation. On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO Tariff provisions associated with calculating Initial Reference Levels and Local Clearing Requirements, effective as of the 2016-2017 PRA. Under the order, FERC found that the existing tariff provision which bases Initial Reference Levels for capacity supply offers on the estimated opportunity cost of exporting capacity to a neighboring region (for example, PJM) are no longer just and reasonable. Accordingly, FERC required MISO to set the Initial Reference Level for the capacity at $0 per MW-day for the 2016-2017 PRA. Capacity suppliers may also request a facility-specific reference level from the MISO IMM. The order did not address the arguments of the complainants regarding the 2015-2016 Auction, and stated that those issues remain under consideration and will be addressed in a future order. New Source Review and Clean Air Act Matters New Source Review. 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 New Source Review and New Source Performance Standard provisions under the Clean Air Act (“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. CAA Section 114 Information Requests. Commencing in 2005, we received a series of information requests from the EPA pursuant to Section 114(a) of the CAA. The requests sought detailed operating and maintenance history data with respect to the Coffeen, Newton and Joppa facilities. In August 2012, the EPA issued a Notice of Violation (“NOV”) alleging that projects performed in 1997, 2006 and 2007 at the Newton facility violated Prevention of Significant Deterioration, Title V permitting and other requirements. The NOV remains unresolved. We believe our defenses to the allegations described in the NOV are meritorious. A decision by the U.S. Court of Appeals for the Seventh Circuit in 2013 held that similar claims older than five years were barred by the statute of limitations. This decision may provide an additional defense to the allegations in the NOV. Ultimate resolution of any of these CAA 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. Groundwater. Groundwater monitoring results indicate that the CCR surface impoundments at the Newton, Coffeen and Joppa facilities potentially impact onsite groundwater. In 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. In April 2015, we submitted an assessment monitoring report to the Illinois EPA concerning previously reported groundwater quality standard exceedances at the Newton facility’s active CCR landfill. The report identifies the Newton facility’s inactive unlined landfill as the likely source of the exceedances and recommends various measures to minimize the effects of that source on the groundwater monitoring results of the active landfill. If remediation measures concerning groundwater are necessary at any of our facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required. 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, equipment, design and construction, plant sites and power generation assets. The following describes the more significant commitments outstanding at December 31, 2015 . Coal Purchase Commitments. At December 31, 2015 , we had contracts in place to purchase coal for our generation facilities with aggregate minimum commitments of $369 million . To the extent forecasted volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar. Coal Transportation. At December 31, 2015 , we had coal transportation contracts and rail car leases in place for our generation facilities with aggregate minimum commitments of $407 million . Environmental Compliance Obligations. We estimate costs, excluding capitalized interest, of approximately $186 million for the completion of scheduled milestones related to the installation of the Newton flue gas desulfurization (“FGD”) systems, such that the IPH fleet will comply with certain SO 2 emission limits approved in the variance granted by the IPCB in November 2013. Please read Business-Environmental Matters-IPH Variance for further details. The first milestone relating to engineering design was completed by July 2015, while the last milestone requires major equipment components being placed into final position on or before September 1, 2019. We are currently scheduled to complete the Newton FGD system project by the end of 2019 with minimal costs anticipated in 2020. Either party can terminate this contract based on certain events as specified in the contract. In February 2016, we issued a notice to the third party contractor constructing the FGD systems directing them to temporarily suspend a portion of the work being performed. We will assess the results of the MISO Planning Year 2016-2017 capacity auction to be held in April 2016, at which time we will reevaluate our suspension notice to the third party contractor constructing the FGD systems. Other Obligations. We have a facilities service agreement obligation of $4 million to maintain transmission system stability in connection with our Coffeen facility through 2039 and other miscellaneous items which are individually insignificant. Indemnifications and Guarantees In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales agreements, and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, management considers the probability of loss to be remote. Guaranty Agreement. Genco has provided an uncapped Guaranty Agreement of certain credit support obligations and tax and environmental indemnification obligations of IPH under a transaction agreement with Ameren Corporation. Certain of the guaranteed obligations under the Guaranty Agreement will survive indefinitely.

Savings and Pension and Other P

Savings and Pension and Other Post-Retirement Benefit Plans	12 Months Ended
	Dec. 31, 2015
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Savings and Pension and Other Post-Retirement Benefit Plans	Note 14—Savings and Pension and Other Post-Retirement Benefit Plans Savings Plans Effective December 2, 2013, our employees, excluding the EEI employees, participate in the Dynegy Inc. 401(k) Plan. The Ameren 401(k) plan covered all eligible employees, including our employees, prior to December 2, 2013, the date of the AER Acquisition. 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 and contributions stopped as of that date and EEI participants became eligible to participate in the Dynegy Inc. 401(k) Plan. These plan benefits were merged into the Dynegy Inc. 401(k) Plan on June 26, 2014. 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 Dynegy Inc. 401(k) Plan was $1 million , $1 million and zero for the years ended December 31, 2015, 2014 and the period from December 2, 2013 through December 31, 2013, respectively. Our portion of the matching contribution to the Ameren 401(k) plan was $1 million for the period from January 1 through December 1, 2013. The matching contribution to the EEI 401(k) plans was less than $1 million for the years ended December 31, 2015, 2014 and 2013. Pension and Other Post-Employment Benefits We offer defined benefit pension and postretirement benefit plans covering our employees. Effective December 2, 2013, our employees and retirees, excluding EEI employees and retirees, participate in Dynegy’s single-employer pension and other postretirement plans. 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. 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 Operating and maintenance expense in our consolidated statements of operations. In August 2015, we finalized certain new collective bargaining agreements that resulted in amendments to certain post-employment benefit plans. As a result of these amendments, we remeasured our benefit obligations and the funded status of the affected plans during the third quarter of 2015. 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 Dynegy’s single-employer pension and postretirement plans on December 2, 2013 and thereafter and Ameren’s single-employer pension and postretirement plans through December 1, 2013. The allocation of obligations, plan assets and costs from our participation in Dynegy’s and Ameren’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 Dynegy’s and Ameren’s single-employer postretirement plans was based on the number of our employees. Obligations and Funded Status. The following tables contain information about the obligations, plan assets and funded status of our pension and postretirement benefit plans as of December 31, 2015 and 2014. 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 Dynegy’s and Ameren’s single-employer pension and postretirement plans. Pension Benefits Other Benefits Year Ended December 31, Year Ended December 31, (amounts in millions) 2015 2014 2015 2014 Benefit obligation, beginning of the year $ 89 $ 89 $ 60 $ 50 Service cost 3 3 1 1 Interest cost 3 4 2 2 Actuarial (gain) loss (3 ) 7 (6 ) 11 Benefits paid (8 ) (5 ) (3 ) (4 ) Plan change — — (8 ) — Settlements — (9 ) (1 ) — Benefit obligation, end of the year $ 84 $ 89 $ 45 $ 60 Fair value of plan assets, beginning of the year $ 70 $ 75 $ 68 $ 67 Actual return on plan assets (1 ) 6 2 5 Employer contributions 4 3 — — Benefits paid (8 ) (5 ) (3 ) (4 ) Settlements — (9 ) — — Fair value of plan assets, end of the year $ 65 $ 70 $ 67 $ 68 Funded status $ (19 ) $ (19 ) $ 22 $ 8 Our accumulated benefit obligation related to pension plans was $84 million and $89 million as of December 31, 2015 and 2014, respectively. Our accumulated benefit obligation related to other post-employment plans was $45 million and $60 million as of December 31, 2015 and 2014, respectively. Amounts recognized in the consolidated balance sheets consist of: Pension Benefits Other Benefits Year Ended December 31, Year Ended December 31, (amounts in millions) 2015 2014 2015 2014 Noncurrent asset (1) $ — $ — $ 23 $ 15 Noncurrent liability (19 ) (19 ) (1 ) (7 ) Net amount recognized $ (19 ) $ (19 ) $ 22 $ 8 _________________________________________ (1) The EEI union postretirement plan was over-funded as of December 31, 2015 and 2014 which was included in our balance sheets in “Other assets.” Pre-tax amounts recognized in AOCI consist of: Pension Benefits Other Benefits Year Ended December 31, Year Ended December 31, (amounts in millions) 2015 2014 2015 2014 Prior service credit $ (2 ) $ (3 ) $ (42 ) $ (39 ) Actuarial loss (gain) 21 20 42 50 Net loss recognized $ 19 $ 17 $ — $ 11 The estimated amounts that will be amortized from accumulated OCI into net periodic benefit cost in 2016 are as follows: (amounts in millions) Pension Benefits (1) Other Benefits (1) Prior service credit $ — $ (5 ) Net actuarial loss (gain) 1 3 Total $ 1 $ (2 ) _________________________________________ (1) 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. Components of Net Periodic Benefit Cost (Gain). The following tables present the components of our net periodic benefit cost (gain) of the EEI pension and postretirement benefit plans and an allocation of net periodic benefit costs from our participation in Dynegy’s and Ameren’s pension and postretirement benefit plans: Pension Benefits Year Ended December 31, (amounts in millions) 2015 2014 2013 Service cost $ 3 $ 3 $ 5 Interest cost 3 4 10 Expected return on plan assets (4 ) (5 ) (13 ) Amortization of: Prior service credit — — (1 ) Actuarial loss 1 1 6 Net periodic benefit cost 3 3 7 Settlements — 2 1 Total benefit cost $ 3 $ 5 $ 8 Other Benefits Year Ended December 31, (amounts in millions) 2015 2014 2013 Service cost $ 1 $ 1 $ 2 Interest cost 2 2 3 Expected return on plan assets (3 ) (3 ) (5 ) Amortization of: Prior service credit (5 ) (4 ) (8 ) Actuarial loss 3 3 5 Net periodic benefit cost (gain) (2 ) (1 ) (3 ) Curtailment gain (1) — — (26 ) Total benefit cost (gain) $ (2 ) $ (1 ) $ (29 ) _________________________________________ (1) Represents EEI’s management postretirement benefit plans’ curtailment gain recognized due to a reduction of employees as a result of the AER Acquisition. In addition to the above net periodic benefit cost for pension benefits, we were allocated $1 million in net periodic benefit costs from Ameren Services employees doing work on our behalf during the period from January 1, 2013 through December 1, 2013. We were also allocated less than $1 million in net periodic benefit costs for postretirement benefits from Ameren Services employees doing work on our behalf during the period from January 1, 2013 through December 1, 2013. Assumptions. The following table presents the assumptions used to determine our benefit obligations: Pension Benefits Other Benefits Year Ended December 31, Year Ended December 31, 2015 2014 2015 2014 Discount rate (1) 4.35 % 4.00 % 4.35 % 4.00 % Rate of compensation increase (1) 3.50 % 3.50 % 3.50 % 3.50 % _________________________________________ (1) A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans at December 31, 2015 and 2014. The following table presents the assumptions used to determine net periodic benefit cost: Pension Benefits Other Benefits Year Ended December 31, Year Ended December 31, 2015 2014 2013 2015 2014 2013 Discount rate (1) 4.35 % 4.00 % (2) 4.35 % 4.00 % (3) Expected return on plan assets (1) 5.82 % 6.16 % 7.65 % 5.86 % 6.26 % 7.59 % Rate of compensation increase (1) 3.50 % 3.50 % (4) 3.50 % 3.50 % (5) _________________________________________ (1) A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans for the years ended December 31, 2015 and 2014. A weighted average rate of EEI’s and Ameren’s pension and postretirement plans for the year ended December 31, 2013. (2) The discount rate used for EEI’s pension plan was 4.00 percent and 4.67 percent 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 percent for the period from January 1, 2013 through December 1, 2013. (3) The discount rate used for EEI’s postretirement plans was 4.00 percent for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 4.00 percent for EEI union employees and 4.75 percent 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 percent for the period from January 1, 2013 through December 1, 2013. (4) The average rate of compensation increase used for EEI’s pension plan was 5.97 percent and 3.50 percent 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 percent for the period from January 1, 2013 through December 1, 2013. (5) The average rate of compensation increase used for EEI’s postretirement plans was 6.35 percent for EEI union employees and 3.81 percent for EEI management employees for the period from January 1, 2013 through December 1, 2013 and 6.35 percent for EEI union employees and 3.50 percent for EEI management employees for 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 percent for the period from January 1, 2013 through December 1, 2013. Our expected long-term rate of return on Dynegy’s pension plan assets and EEI’s pension plan assets is 5.60 percent and 5.90 percent , respectively, for the year ended December 31, 2016. Our expected long-term rate of return on EEI’s other post-employment plan assets is 6.30 percent for EEI union employees and 5.75 percent for EEI salaried employees for the year ended December 31, 2016. This figure begins with a blend of asset class-level returns developed under a theoretical global capital asset pricing model methodology conducted by an outside consultant. In development of this figure, the historical relationships between equities and fixed income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long term. Current market factors such as inflation and interest rates are also incorporated in the assumptions. This figure gives consideration towards the plan’s use of active management and favorable past experience. It is also net of plan expenses. The following summarizes our assumed health care cost trend rates: Other Benefits Year Ended December 31, 2015 2014 2013 Dynegy - Health care cost trend rate assumed for next year 7.00 % 7.25 % N/A Dynegy - Ultimate trend rate 4.50 % 4.50 % N/A Dynegy - Year that the rate reaches the ultimate trend rate 2023 2023 N/A Ameren - Health care cost trend rate assumed for next year N/A N/A 5.00 % Ameren - Ultimate trend rate N/A N/A 5.00 % Ameren - Year that the rate reaches the ultimate trend rate N/A N/A 2013 EEI - Health care cost trend rate assumed for next year 7.00 % 7.25 % (1) EEI - Ultimate trend rate 4.50 % 4.50 % 4.50 % EEI - Year that the rate reaches the ultimate trend rate 2023 2023 (2) _________________________________________ (1) The health care trend rate assumed for next year used for EEI’s postretirement plans was 7.96 percent for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 7.96 percent for EEI union employees and 7.75 percent for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively. (2) The year that the rate reaches the ultimate trend rate used for EEI’s postretirement plans was 2027 for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 2027 for EEI union employees and 2023 for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The impact of a one percent increase/decrease in assumed health care cost trend rates is as follows: (amounts in millions) Increase Decrease Aggregate impact on service cost and interest cost (1) $ — $ — Impact on accumulated post-employment benefit obligation (1) $ 6 $ (5 ) _________________________________________ (1) Includes amounts only for EEI’s plans. Plan Assets. We employ a total return investment approach whereby a mix of equity and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. The intent of this strategy is to minimize plan expenses by outperforming plan liabilities over the long run. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks as well as growth, value, and small and large capitalizations. The target asset mix for EEI’s plan assets as of December 31, 2015 was approximately 60 percent to equity investments and approximately 40 percent to fixed income investments. EEI’s plan assets are routinely monitored and rebalanced as circumstances warrant. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investment. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, periodic asset/liability studies and annual liability measurements. As described above, a portion of Dynegy’s pension and postretirement plan assets is allocated to us as of December 31, 2015 and 2014. The amount of Dynegy pension plan assets allocated to us for financial reporting purposes as of December 31, 2015 and 2014 was $2 million and $2 million , respectively, based on pensionable salaries. None of the Dynegy postretirement plan assets were allocated to us for financial reporting purposes as of December 31, 2015 and 2014 based on the number of our non-EEI employees. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value related to our EEI pension and other post-employment plans. These assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Fair Value as of December 31, 2015 (amounts in millions) Quoted Prices in Active Markets for Identified Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Other Unobservable Inputs (Level 3) Total Cash and cash equivalents $ 1 $ — $ — $ 1 Equity securities: U.S. companies (1) 32 33 — 65 International (3) 7 5 — 12 Fixed income securities (4) 14 38 — 52 Total $ 54 $ 76 $ — $ 130 Fair Value as of December 31, 2014 (amounts in millions) Quoted Prices in Active Markets for Identified Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Other Unobservable Inputs (Level 3) Total Cash and cash equivalents $ 2 $ — $ — $ 2 Equity securities: U.S. companies (1) 6 62 — 68 Non-U.S. companies (2) — — — — International (3) 2 10 — 12 Fixed income securities (4) 3 51 — 54 Total $ 13 $ 123 $ — $ 136 ________________________________________ (1) This category comprises a domestic common collective trust not actively managed that tracks the Dow Jones total U.S. stock market. (2) This category comprises a common collective trust not actively managed that tracks the MSCI All Country World Ex-U.S. Index. (3) This category comprises actively managed common collective trusts that hold U.S. and foreign equities. These trusts track the MSCI World Index. (4) This category includes a mutual fund and a trust that invest primarily in investment grade corporate bonds. Contributions and Payments. We were required to make contributions of $4 million and $3 million to EEI's pension plan during the years ended December 31, 2015 and 2014, respectively. We are not required to make any contributions to our pension plans during 2016. The following table presents the cash contributions made to our pension benefit plans: Pension Benefits Year Ended December 31, (amounts in millions) 2015 2014 2013 Allocation (1) $ — $ — $ 5 EEI 4 3 10 Total $ 4 $ 3 $ 15 _________________________________________ (1) Represents an allocation of our share of cash contributions associated with our participation in Ameren’s pension plan for the year ended December 31, 2013. There was no allocation of our share of cash contributions associated with our participation in Dynegy’s pension plan for the years ended December 31, 2015 and 2014. Our current funding policies are to forego further contributions to their postretirement benefit plans, except as necessary to fund benefit payments. There were no employer contributions to our postretirement plans for the years ended December 31, 2015, 2014 and 2013. The expected pension and postretirement benefit payments for expected future service, as of December 31, 2015, are as follows: (amounts in millions) Pension Benefits (1) Other Benefits (1) 2016 $ 8 $ 2 2017 $ 7 $ 2 2018 $ 7 $ 2 2019 $ 7 $ 2 2020 $ 6 $ 2 2021 - 2025 $ 30 $ 12 _________________________________________ (1) Includes only amounts for EEI’s plans.

Quarterly Financial Information

Quarterly Financial Information	12 Months Ended
	Dec. 31, 2015
Selected Quarterly Financial Information [Abstract]
Quarterly Financial Information	Note 15—Quarterly Financial Information The following is a summary of our unaudited quarterly financial information: Quarter Ended (amounts in millions) March 31 June 30 September 30 December 31 2015 Revenues $ 143 $ 131 $ 146 $ 114 Operating loss (1) $ (17 ) $ (24 ) $ (855 ) $ (6 ) Net loss $ (16 ) $ (19 ) $ (517 ) $ (11 ) Net loss attributable to Illinois Power Generating Company $ (15 ) $ (17 ) $ (519 ) $ (11 ) Quarter Ended (amounts in millions) March 31 June 30 September 30 December 31 2014 Revenues $ 180 $ 138 $ 165 $ 165 Operating income (loss) $ 3 $ (35 ) $ (18 ) $ (7 ) Net loss $ (4 ) $ (27 ) $ (17 ) $ — Net loss attributable to Illinois Power Generating Company $ (6 ) $ (27 ) $ (17 ) $ — __________________________________________ (1) The results for the three months ended September 30, 2015, include an impairment charge of $855 million . See Note 3—Impairments for more information.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Principles of Consolidation and Basis of Presentation	Principles of Consolidation and Basis of Presentation. The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries. Intercompany accounts and transactions have been eliminated. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. Certain prior period amounts in our consolidated statements of operations have been reclassified to conform to current year presentation. Accounting policies for all of our operations are in accordance with accounting principles generally accepted in the United States of America.
Noncontrolling Interest	Noncontrolling Interest. Noncontrolling interest is comprised of the 20 percent of EEI we do not own. This noncontrolling interest is classified as a component of equity separate from our equity in our consolidated balance sheets.
Use of Estimates	Use of Estimates. The preparation of consolidated financial statements in conformity with Generally Accepted Accounting Principles (“GAAP”) requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing tangible assets for possible impairment, (iii) estimating the useful lives of our assets and Asset Retirement Obligations (“AROs”), (iv) assessing future tax exposure and the realization of deferred tax assets, (v) determining amounts to accrue for contingencies, guarantees and indemnifications and (vi) estimating various factors used to value our pension assets and liabilities. Actual results could differ materially from our estimates.
Inventory	Inventory. Our commodity and materials and supplies inventories are carried at the lower of weighted average cost and net realizable value (“NRV”).
Property, Plant and Equipment	Property, Plant and Equipment. Property, plant and equipment, which consist principally of power generating facilities, including capitalized interest, is generally recorded at historical cost. 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. Depreciation is provided using the straight-line method over the estimated economic service lives of the assets, ranging from 2 to 30 years. The estimated economic service lives of our asset groups are as follows: Asset Group Range of Years Power generation 3 to 30 Buildings and improvements 2 to 30 Office and other equipment 3 to 20
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 3—Impairments for further discussion.
Asset Retirement Obligations	Asset Retirement Obligations. We record the present value of our legal obligations to retire tangible, long-lived assets on our balance sheets as liabilities when the liability is incurred. Our AROs relate to activities such as Coal Combustion Residuals (“CCR”) surface impoundment and landfill closure, dismantlement of power generation facilities, future removal of asbestos containing material from certain power generation facilities, closure and post-closure costs, environmental testing, remediation, monitoring and land obligations. In subsequent periods, we make upward or downward revisions to AROs in accordance with GAAP. 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. Accretion expense is included in Operating and maintenance expense on our consolidated statements of operations.
Contingencies, Commitments, Guarantees and Indemnifications	Contingencies, Commitments, Guarantees and Indemnifications. We are involved in numerous lawsuits, claims, proceedings and tax-related audits in the normal course of our operations. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies on an ongoing basis to ensure that we have appropriate reserves recorded on our consolidated balance sheets. These reserves are based on estimates and judgments made by management with respect to the likely outcome of these matters, including any applicable insurance coverage for litigation matters, and are adjusted as circumstances warrant. Liabilities for environmental contingencies are recorded when an environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability.
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 PSAs with Illinois Power Marketing Company (“IPM”). Revenue is recognized when the product or service is delivered to a customer, unless they meet the definition of a derivative.
Fair Value Measurements	Fair Value Measurements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Our estimate of fair value reflects the impact of credit risk. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs are classified as readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the classification of the inputs used to calculate the fair value of a transaction. The inputs used to measure fair value have been placed in a hierarchy based on priority. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: • Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities. • Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using industry-standards models or other valuation methodologies, in which substantially all assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter forwards, options and swaps. • Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to our needs. At each balance sheet date, we perform an analysis of all instruments and include in Level 3 all of those whose fair value is based on significant unobservable inputs. The determination of fair value incorporates various factors. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities. Valuation adjustments are generally based on capital market implied ratings evidence when assessing the credit standing of our counterparties and when applicable, adjusted based on management’s estimates of assumptions market participants would use in determining fair value.
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 entered into a tax sharing agreement effective December 2, 2013, which was amended and restated as of December 31, 2014. Under the terms of the new tax sharing agreement, we recognize taxes based on a separate company income tax return basis and settle taxes with Dynegy at the discretion of either Dynegy’s or Genco’s management, as defined in the agreement. As a result of the AER Acquisition, we are under IRC Section 382, and are subject to a limitation in the amount of net operating losses (“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 . Please read Note 12—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.
Employee Separation and Other Charges	Employee Separation and Other Charges. Employee separation programs were initiated as a result of the AER Acquisition to reduce positions under terms and benefits consistent with our former parent Ameren’s standard management separation program. We recorded pretax charges related to these programs of less than $1 million , and $3 million for the years ended December 31, 2014 and 2013, respectively. These charges were recorded in Operating and maintenance expense on the consolidated statements of operations. There were no charges incurred in 2015, and we do not expect to pay out severance benefits in 2016.
Accounting Standards Adopted	Accounting Standards Adopted Income Taxes. In November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-17-Income Taxes (Topic 740). The amendment in this ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The guidance in this ASU is effective for public entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period. The ASU may be applied prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We adopted ASU 2015-17 as of December 31, 2015 and applied the guidance prospectively with no change to prior period amounts disclosed in our consolidated balance sheets and related notes to the consolidated financial statements. Please read Note 12—Income Taxes for further details. Derivatives. In August 2015, the FASB issued Accounting Standards Update ASU 2015-13-Derivatives and Hedging (Topic 815). The amendments in this ASU specify that the use of locational marginal pricing by an ISO does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis and, therefore, does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. If the physical delivery criterion is met, along with all of the other criteria of the normal purchases and normal sales scope exception, an entity may elect to designate that contract as a normal purchase or normal sale. The amendments in this ASU are effective upon issuance and should be applied prospectively. The adoption of this ASU did not have a material impact on our consolidated financial statements. Inventory. In July 2015, the FASB issued ASU 2015-11-Inventory (Topic 330). The amendments in this ASU require that inventory is measured at the lower of cost and NRV, with the latter defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This ASU eliminates the need to determine market or replacement cost and evaluate whether it is above the ceiling at NRV or below the floor (NRV less a normal profit margin). The guidance in this ASU is effective prospectively for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted ASU 2015-11 as of July 1, 2015. The adoption of this ASU did not have a material impact on our consolidated financial statements. Retirement Benefits. In April 2015, the FASB issued ASU 2015-04-Compensation-Retirement Benefits (Topic 715). For an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan or post retirement plan assets and obligations, the amendments in this Update provide a practical expedient that permits the entity to remeasure the plan assets and obligations using the month-end that is closest to the date of the significant event. The month-end remeasurement of defined benefit plan assets and obligations that is closest to the date of the significant event should be adjusted for any effects of the significant event that may or may not be captured in the month-end measurement. An entity is required to disclose the accounting policy election and the date used to measure defined benefit plan assets and obligations in accordance with the amendments in this Update. The amendments in this Update are effective for public business entities for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption allowed. The amendments in this Update should be applied prospectively. We adopted the guidance in this ASU on July 1, 2015. The adoption of this ASU did not have a material impact on our consolidated financial statements. Reporting Discontinued Operations and Asset Disposals. In April 2014, the FASB issued ASU 2014-08-Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosure of Disposals of Components of an Entity. The amendments in this ASU change the requirements for reporting discontinued operations in Subtopic 205-20. An entity is required to report within discontinued operations on the statement of operations the results of a component or group of components of an entity if the disposal represents a strategic shift that has, or will have, a major effect on an entity’s operations and financial results. Additionally, the associated assets and liabilities are required to be presented separately from other assets and liabilities on the balance sheet for all comparative periods. The ASU includes updated guidance regarding what meets the definition of a component of an entity. The new financial statement presentation provisions relating to this ASU are prospective and effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. We adopted the guidance in this ASU on January 1, 2015. The adoption of this ASU did not have a material impact on our financial statements or disclosures.
Accounting Standards Not Yet Adopted	Accounting Standards Not Yet Adopted Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The amendments in this ASU will mainly require lessees to recognize lease assets and lease liabilities, for those leases classified as operating leases under GAAP, in their balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our consolidated financial statements. Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. In August 2015, the FASB issued ASU 2015-15-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU further clarify the guidance provided in ASU 2015-03 to include the presentation of debt issuance costs in relation to line-of-credit arrangements. The amendments state these costs may be presented as an asset and subsequently amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance in these ASUs is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The adoption of these ASUs should be applied on a retrospective basis, affecting all balance sheet periods presented. We do not anticipate the adoption of these ASUs will have a material impact on our consolidated balance sheets. Extraordinary and Unusual Items. In January 2015, the FASB issued ASU 2015-01-Income Statement-Extraordinary and Unusual Items (Subtopic 225-20). The amendments in this ASU eliminate from GAAP the concept of extraordinary items and will no longer require separate classification of these items within the statement of operations. Presentation and disclosure guidance for items that are unusual in nature or occur infrequently will be retained and will be expanded to include items that are both unusual in nature and infrequently occurring. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Reporting entities may elect to apply the amendments prospectively only, or retrospectively for all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. We do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements. Going Concern. In August 2014, the FASB issued ASU 2014-15-Presentation of Financial Statements - Going Concern (Subtopic 205-40). The amendments in this ASU requires management, in connection with preparing financial statements for each annual and interim reporting period, to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). Currently, there is no guidance in GAAP about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern or to provide related footnote disclosures. The amendments in this ASU provide that guidance. In doing so, the amendments should reduce diversity in the timing and content of footnote disclosures. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We currently do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements. Revenue from Contracts with Customers. In May 2014, the FASB and International Accounting Standards Board jointly issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU was further updated through the issuance of ASU 2015-14 in August 2015. The amendments in this ASU develop a common revenue standard for GAAP and International Financial Reporting Standards by removing inconsistencies and weaknesses in revenue requirements, providing a more robust framework for addressing revenue issues, improving comparability of revenue recognition practices, providing more useful information to users of financial statements and simplifying the preparation of financial statements. The guidance in this ASU is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are currently assessing this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements.

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Property, Plant and Equipment	The estimated economic service lives of our asset groups are as follows: Asset Group Range of Years Power generation 3 to 30 Buildings and improvements 2 to 30 Office and other equipment 3 to 20 A summary of our property, plant and equipment is as follows: December 31, (amounts in millions) 2015 2014 Power generation $ 1,511 $ 2,710 Building and improvements 212 276 Office and other equipment 27 30 Property, plant and equipment $ 1,750 $ 3,016 Less: Accumulated depreciation and amortization (813 ) (1,145 ) Property, plant and equipment, net $ 937 $ 1,871
Schedule of Asset Retirement Obligations	The following table provides a reconciliation of the beginning and ending carrying amounts of AROs for the year ended December 31, 2015: (amounts in millions) Balance at December 31, 2013 $ 43 Accretion expense 3 Revision of previous estimate (1) 44 Balance at December 31, 2014 90 Accretion expense 9 Revision of previous estimate (2) (50 ) Balance at December 31, 2015 $ 49 __________________________________________ (1) During 2014, we revised our ARO upward by $44 million based on observed trends in Illinois primarily related to CCR surface impoundment closures, groundwater monitoring and updated cost estimates for asbestos in accordance with the standards used in the industry. (2) During 2015, we revised our ARO downward by $50 million based on management’s review and assessment of CCR compliance timing and site specific analysis.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value, by Balance Sheet Grouping	All fair values presented below are classified within Level 2 of the fair value hierarchy. December 31, 2015 December 31, 2014 (amounts in millions) Carrying Amount Fair Value Carrying Amount Fair Value 7.00% Senior Notes Series H, due 2018 $ 300 $ 204 $ 300 $ 264 6.30% Senior Notes Series I, due 2020 $ 250 $ 148 $ 250 $ 208 7.95% Senior Notes Series F, due 2032 (1) $ 274 $ 162 $ 274 $ 241 __________________________________________ (1) Carrying amount includes unamortized discount of $1 million as of December 31, 2015 and 2014 . Please read Note 10—Debt for further discussion.

Accumulated Other Comprehensi27

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	Changes in accumulated other comprehensive income (loss), net of tax, by component are as follows: Year Ended December 31, (amounts in millions) 2015 2014 2013 Beginning of period $ (16 ) $ (11 ) $ (40 ) Other comprehensive income (loss) before reclassifications: Actuarial gain (loss) and plan amendments (net of tax benefit (expense) of $3, $4, and ($8), respectively) 6 (8 ) 12 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, zero and zero, respectively) (1) 1 1 1 Settlement loss on pension plan (net of tax benefit of zero, zero and zero, respectively) (2) — 2 — Amortization of unrecognized prior service credit and actuarial loss (net of tax expense of zero, zero, and $1, respectively) (3) (1 ) — 1 Reclassification of curtailment gain included in net loss (net of tax benefit of zero, zero, and $9, respectively) (4) — — (13 ) Net current period other comprehensive income (loss), net of tax 6 (5 ) 1 AER Acquisition (net of tax expense of zero, zero, and $20, respectively) (5) — — 28 End of period $ (10 ) $ (16 ) $ (11 ) __________________________________________ (1) Amount related to the reclassification of mark-to-market loss on cash flow hedging activities, net and was recorded in Interest expense on our consolidated statements of operations. Please read Note 4—Derivative Financial Instruments for further discussion. (2) Amount related to the settlement loss on the EEI pension plan and is included in the computation of total benefit cost (gain). Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion. (3) Amounts are associated with our defined benefit pension and other post-retirement benefit plans and are included in the computation of net periodic benefit cost (gain). Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion. (4) Amount related to the EEI curtailment gain on pension and postretirement benefit plans and was recorded in Operating and maintenance expense in our consolidated statements of operations. Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion. (5) 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 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.

Cash Flow Information (Tables)

Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	Following are supplemental disclosures of cash flow and non-cash investing and financing information: Year Ended December 31, (amounts in millions) 2015 2014 2013 Interest paid (net of amount capitalized) $ 37 $ 39 $ 41 Income taxes, net $ — $ — $ (65 ) Other non-cash investing and financing activity: Non-cash capital expenditures (1) $ — $ 3 $ 3 Capital contributions from parent $ — $ — $ 72 __________________________________________ (1) These expenditures are primarily for changes in our accruals of capital expenditures for all years presented.

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Schedule of Inventory, Current	A summary of our inventories is as follows: December 31, (amounts in millions) 2015 2014 Materials and supplies $ 30 $ 30 Coal 102 51 Fuel oil 1 1 Total $ 133 $ 82

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
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 3 to 30 Buildings and improvements 2 to 30 Office and other equipment 3 to 20 A summary of our property, plant and equipment is as follows: December 31, (amounts in millions) 2015 2014 Power generation $ 1,511 $ 2,710 Building and improvements 212 276 Office and other equipment 27 30 Property, plant and equipment $ 1,750 $ 3,016 Less: Accumulated depreciation and amortization (813 ) (1,145 ) Property, plant and equipment, net $ 937 $ 1,871
Summary of Total Interest Costs Incurred and Interest Capitalized for Construction in Progress	The following table summarizes total interest costs incurred and interest capitalized related to costs of construction projects in process: Year Ended December 31, (amounts in millions) 2015 2014 2013 Total interest costs incurred $ 59 $ 59 $ 60 Capitalized interest $ 22 $ 20 $ 18

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Outstanding	A summary of our long-term debt is as follows: December 31, (amounts in millions) 2015 2014 Unsecured notes: 7.00% Senior Notes Series H, due 2018 $ 300 $ 300 6.30% Senior Notes Series I, due 2020 250 250 7.95% Senior Notes Series F, due 2032 275 275 825 825 Unamortized discount (1 ) (1 ) Total long-term debt $ 824 $ 824
Schedule of Required and Actual Debt Ratios	The following table summarizes these required ratios: Required Ratio Restricted payment interest coverage ratio (1) ≥1.75 Additional indebtedness interest coverage ratio (2) ≥2.50 Additional indebtedness debt-to-capital ratio (2) ≤60% _______________________________________ (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.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table summarizes the affiliate accounts receivable and payable on our consolidated balance sheets. December 31, 2015 December 31, 2014 (amounts in millions) Accounts Receivable, Affiliates Accounts Payable, Affiliates Accounts Receivable, Affiliates Accounts Payable, Affiliates Power supply agreements $ 54 $ — $ 88 $ — Services agreement — 5 — 1 Tax sharing agreement — 3 — 5 Other (1) — 10 — 7 Total $ 54 $ 18 $ 88 $ 13 __________________________________________ (1) As of December 31, 2015 , approximately $10 million of the accounts payable, affiliate balance is comprised of reimbursable employee benefits paid by a Dynegy subsidiary on behalf of Genco. The following table presents the impact of related party transactions on our consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013. Year Ended December 31, (amounts in millions) Income Statement Line Item 2015 2014 2013 Power supply agreements Revenues $ 530 $ 646 $ 709 Services provided to AER affiliates Revenues $ — $ — $ 6 Ameren Missouri gas transportation agreement Cost of sales $ — $ — $ 1 EEI power supply agreement Cost of sales $ — $ — $ 66 Services agreement Operating and maintenance expense $ 34 $ 43 $ 13

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule Of Effective Income Tax Rate Reconciliation	e following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate: Year Ended December 31, 2015 2014 2013 Statutory federal income tax rate: 35 % 35 % 35 % Increases (decreases) from: State tax 5 6 6 Acquisition adjustment (1) — 9 (15 ) Effective income tax rate 40 % 50 % 26 % _________________________________________ (1) Acquisition adjustments relating to the impacts of the change in ownership under IRC Section 382 and other tax attribute reductions.
Schedule Of Components Of Income Tax Expense (Benefit)	The following table presents the components of income tax benefit: Year Ended December 31, (amounts in millions) 2015 2014 2013 Current taxes: Federal $ — $ 1 $ 50 State — — 14 Deferred taxes: Federal 305 39 (6 ) State 73 9 6 Deferred investment tax credits, amortization — — 1 Total income tax benefit $ 378 $ 49 $ 65
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) 2015 2014 Accumulated deferred income taxes, net liability (asset): Plant related $ 167 $ 551 Deferred employee benefit costs (1 ) (6 ) ARO (15 ) (36 ) NOLs (25 ) (7 ) Other (7 ) (9 ) Total net accumulated deferred income tax liabilities $ 119 $ 493
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) 2015 2014 2013 Unrecognized tax benefits - beginning of year $ — $ — $ 6 Increases based on tax positions prior to current year — — 2 Decreases based on tax positions prior to current year — — (3 ) Decreases based on tax positions related to current year — — (1 ) Adjustment of balance due to change in ownership — — (3 ) Decreases related to the lapse of statute of limitations — — (1 ) Unrecognized tax benefits - end of year $ — $ — $ — Total unrecognized tax benefits (detriments) that, if recognized, would affect the effective tax rates $ — $ — $ —
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) 2015 2014 2013 Liability for interest - beginning of year $ — $ — $ 1 Adjustment of balance due to change in ownership — — (1 ) Liability for interest - end of year $ — $ — $ —

Savings and Pension and Other34

Savings and Pension and Other Post-Retirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Schedule of Net Funded Status	The following tables contain information about the obligations, plan assets and funded status of our pension and postretirement benefit plans as of December 31, 2015 and 2014. 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 Dynegy’s and Ameren’s single-employer pension and postretirement plans. Pension Benefits Other Benefits Year Ended December 31, Year Ended December 31, (amounts in millions) 2015 2014 2015 2014 Benefit obligation, beginning of the year $ 89 $ 89 $ 60 $ 50 Service cost 3 3 1 1 Interest cost 3 4 2 2 Actuarial (gain) loss (3 ) 7 (6 ) 11 Benefits paid (8 ) (5 ) (3 ) (4 ) Plan change — — (8 ) — Settlements — (9 ) (1 ) — Benefit obligation, end of the year $ 84 $ 89 $ 45 $ 60 Fair value of plan assets, beginning of the year $ 70 $ 75 $ 68 $ 67 Actual return on plan assets (1 ) 6 2 5 Employer contributions 4 3 — — Benefits paid (8 ) (5 ) (3 ) (4 ) Settlements — (9 ) — — Fair value of plan assets, end of the year $ 65 $ 70 $ 67 $ 68 Funded status $ (19 ) $ (19 ) $ 22 $ 8
Schedule of Amounts Recognized in Balance Sheet	Amounts recognized in the consolidated balance sheets consist of: Pension Benefits Other Benefits Year Ended December 31, Year Ended December 31, (amounts in millions) 2015 2014 2015 2014 Noncurrent asset (1) $ — $ — $ 23 $ 15 Noncurrent liability (19 ) (19 ) (1 ) (7 ) Net amount recognized $ (19 ) $ (19 ) $ 22 $ 8 _________________________________________ (1) The EEI union postretirement plan was over-funded as of December 31, 2015 and 2014 which was included in our balance sheets in “Other assets.”
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	Pre-tax amounts recognized in AOCI consist of: Pension Benefits Other Benefits Year Ended December 31, Year Ended December 31, (amounts in millions) 2015 2014 2015 2014 Prior service credit $ (2 ) $ (3 ) $ (42 ) $ (39 ) Actuarial loss (gain) 21 20 42 50 Net loss recognized $ 19 $ 17 $ — $ 11 The estimated amounts that will be amortized from accumulated OCI into net periodic benefit cost in 2016 are as follows: (amounts in millions) Pension Benefits (1) Other Benefits (1) Prior service credit $ — $ (5 ) Net actuarial loss (gain) 1 3 Total $ 1 $ (2 ) _________________________________________ (1) Includes only amounts for EEI’s plans.
Components Of Net Periodic Benefit Cost	The following tables present the components of our net periodic benefit cost (gain) of the EEI pension and postretirement benefit plans and an allocation of net periodic benefit costs from our participation in Dynegy’s and Ameren’s pension and postretirement benefit plans: Pension Benefits Year Ended December 31, (amounts in millions) 2015 2014 2013 Service cost $ 3 $ 3 $ 5 Interest cost 3 4 10 Expected return on plan assets (4 ) (5 ) (13 ) Amortization of: Prior service credit — — (1 ) Actuarial loss 1 1 6 Net periodic benefit cost 3 3 7 Settlements — 2 1 Total benefit cost $ 3 $ 5 $ 8 Other Benefits Year Ended December 31, (amounts in millions) 2015 2014 2013 Service cost $ 1 $ 1 $ 2 Interest cost 2 2 3 Expected return on plan assets (3 ) (3 ) (5 ) Amortization of: Prior service credit (5 ) (4 ) (8 ) Actuarial loss 3 3 5 Net periodic benefit cost (gain) (2 ) (1 ) (3 ) Curtailment gain (1) — — (26 ) Total benefit cost (gain) $ (2 ) $ (1 ) $ (29 ) _________________________________________ (1) Represents EEI’s management postretirement benefit plans’ curtailment gain recognized due to a reduction of employees as a result of the AER Acquisition
Assumptions Used To Determine Net Periodic Benefit Cost	The following table presents the assumptions used to determine our benefit obligations: Pension Benefits Other Benefits Year Ended December 31, Year Ended December 31, 2015 2014 2015 2014 Discount rate (1) 4.35 % 4.00 % 4.35 % 4.00 % Rate of compensation increase (1) 3.50 % 3.50 % 3.50 % 3.50 % _________________________________________ (1) A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans at December 31, 2015 and 2014. The following table presents the assumptions used to determine net periodic benefit cost: Pension Benefits Other Benefits Year Ended December 31, Year Ended December 31, 2015 2014 2013 2015 2014 2013 Discount rate (1) 4.35 % 4.00 % (2) 4.35 % 4.00 % (3) Expected return on plan assets (1) 5.82 % 6.16 % 7.65 % 5.86 % 6.26 % 7.59 % Rate of compensation increase (1) 3.50 % 3.50 % (4) 3.50 % 3.50 % (5) _________________________________________ (1) A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans for the years ended December 31, 2015 and 2014. A weighted average rate of EEI’s and Ameren’s pension and postretirement plans for the year ended December 31, 2013. (2) The discount rate used for EEI’s pension plan was 4.00 percent and 4.67 percent 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 percent for the period from January 1, 2013 through December 1, 2013. (3) The discount rate used for EEI’s postretirement plans was 4.00 percent for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 4.00 percent for EEI union employees and 4.75 percent 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 percent for the period from January 1, 2013 through December 1, 2013. (4) The average rate of compensation increase used for EEI’s pension plan was 5.97 percent and 3.50 percent 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 percent for the period from January 1, 2013 through December 1, 2013. (5) The average rate of compensation increase used for EEI’s postretirement plans was 6.35 percent for EEI union employees and 3.81 percent for EEI management employees for the period from January 1, 2013 through December 1, 2013 and 6.35 percent for EEI union employees and 3.50 percent for EEI management employees for 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 percent for the period from January 1, 2013 through December 1, 2013.
Schedule of Health Care Cost Trend Rates	The following summarizes our assumed health care cost trend rates: Other Benefits Year Ended December 31, 2015 2014 2013 Dynegy - Health care cost trend rate assumed for next year 7.00 % 7.25 % N/A Dynegy - Ultimate trend rate 4.50 % 4.50 % N/A Dynegy - Year that the rate reaches the ultimate trend rate 2023 2023 N/A Ameren - Health care cost trend rate assumed for next year N/A N/A 5.00 % Ameren - Ultimate trend rate N/A N/A 5.00 % Ameren - Year that the rate reaches the ultimate trend rate N/A N/A 2013 EEI - Health care cost trend rate assumed for next year 7.00 % 7.25 % (1) EEI - Ultimate trend rate 4.50 % 4.50 % 4.50 % EEI - Year that the rate reaches the ultimate trend rate 2023 2023 (2) _________________________________________ (1) The health care trend rate assumed for next year used for EEI’s postretirement plans was 7.96 percent for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 7.96 percent for EEI union employees and 7.75 percent for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively. (2) The year that the rate reaches the ultimate trend rate used for EEI’s postretirement plans was 2027 for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 2027 for EEI union employees and 2023 for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively.
Sensitivity to potential changes in key assumptions	Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The impact of a one percent increase/decrease in assumed health care cost trend rates is as follows: (amounts in millions) Increase Decrease Aggregate impact on service cost and interest cost (1) $ — $ — Impact on accumulated post-employment benefit obligation (1) $ 6 $ (5 ) _________________________________________ (1) Includes amounts only for EEI’s plans.
Fair Value Inputs, Assets, Quantitative Information [Table Text Block]	Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Fair Value as of December 31, 2015 (amounts in millions) Quoted Prices in Active Markets for Identified Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Other Unobservable Inputs (Level 3) Total Cash and cash equivalents $ 1 $ — $ — $ 1 Equity securities: U.S. companies (1) 32 33 — 65 International (3) 7 5 — 12 Fixed income securities (4) 14 38 — 52 Total $ 54 $ 76 $ — $ 130 Fair Value as of December 31, 2014 (amounts in millions) Quoted Prices in Active Markets for Identified Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Other Unobservable Inputs (Level 3) Total Cash and cash equivalents $ 2 $ — $ — $ 2 Equity securities: U.S. companies (1) 6 62 — 68 Non-U.S. companies (2) — — — — International (3) 2 10 — 12 Fixed income securities (4) 3 51 — 54 Total $ 13 $ 123 $ — $ 136 ________________________________________ (1) This category comprises a domestic common collective trust not actively managed that tracks the Dow Jones total U.S. stock market. (2) This category comprises a common collective trust not actively managed that tracks the MSCI All Country World Ex-U.S. Index. (3) This category comprises actively managed common collective trusts that hold U.S. and foreign equities. These trusts track the MSCI World Index. (4) This category includes a mutual fund and a trust that invest primarily in investment grade corporate bonds.
Expected pension and postretirement benefit payments	The following table presents the cash contributions made to our pension benefit plans: Pension Benefits Year Ended December 31, (amounts in millions) 2015 2014 2013 Allocation (1) $ — $ — $ 5 EEI 4 3 10 Total $ 4 $ 3 $ 15 _________________________________________ (1) Represents an allocation of our share of cash contributions associated with our participation in Ameren’s pension plan for the year ended December 31, 2013. There was no allocation of our share of cash contributions associated with our participation in Dynegy’s pension plan for the years ended December 31, 2015 and 2014. Our current funding policies are to forego further contributions to their postretirement benefit plans, except as necessary to fund benefit payments. There were no employer contributions to our postretirement plans for the years ended December 31, 2015, 2014 and 2013. The expected pension and postretirement benefit payments for expected future service, as of December 31, 2015, are as follows: (amounts in millions) Pension Benefits (1) Other Benefits (1) 2016 $ 8 $ 2 2017 $ 7 $ 2 2018 $ 7 $ 2 2019 $ 7 $ 2 2020 $ 6 $ 2 2021 - 2025 $ 30 $ 12 _________________________________________ (1) Includes only amounts for EEI’s plans.

Quarterly Financial Informati35

Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
Selected Quarterly Financial Information [Abstract]
Summary Of Selected Quarterly Information	The following is a summary of our unaudited quarterly financial information: Quarter Ended (amounts in millions) March 31 June 30 September 30 December 31 2015 Revenues $ 143 $ 131 $ 146 $ 114 Operating loss (1) $ (17 ) $ (24 ) $ (855 ) $ (6 ) Net loss $ (16 ) $ (19 ) $ (517 ) $ (11 ) Net loss attributable to Illinois Power Generating Company $ (15 ) $ (17 ) $ (519 ) $ (11 ) Quarter Ended (amounts in millions) March 31 June 30 September 30 December 31 2014 Revenues $ 180 $ 138 $ 165 $ 165 Operating income (loss) $ 3 $ (35 ) $ (18 ) $ (7 ) Net loss $ (4 ) $ (27 ) $ (17 ) $ — Net loss attributable to Illinois Power Generating Company $ (6 ) $ (27 ) $ (17 ) $ — __________________________________________ (1) The results for the three months ended September 30, 2015, include an impairment charge of $855 million . See Note 3—Impairments for more information.

Organization and Operations (De

Organization and Operations (Details)	Dec. 31, 2015	Dec. 02, 2013
Variable Interest Entity [Line Items]
Percentage of voting interests acquired		100.00%
EEI
Variable Interest Entity [Line Items]
Ownership percentage by parent	80.00%

Summary of Significant Accoun37

Summary of Significant Accounting Policies (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015
Accounting Policies [Line Items]
Operating Loss Carryforwards	$ 0
Severance costs	$ 1,000,000	$ 3,000,000
EEI
Accounting Policies [Line Items]
Noncontrolling interest, ownership percentage by noncontrolling owners			20.00%

Summary of Significant Accoun38

Summary of Significant Accounting Policies (Property, Plant and Equipment) (Details)	12 Months Ended
	Dec. 31, 2015
Minimum
Property, Plant and Equipment [Line Items]
Useful life	2 years
Maximum
Property, Plant and Equipment [Line Items]
Useful life	30 years
Power generation | Minimum
Property, Plant and Equipment [Line Items]
Useful life	3 years
Power generation | Maximum
Property, Plant and Equipment [Line Items]
Useful life	30 years
Building and improvements | Minimum
Property, Plant and Equipment [Line Items]
Useful life	2 years
Building and improvements | Maximum
Property, Plant and Equipment [Line Items]
Useful life	30 years
Office and other equipment | Minimum
Property, Plant and Equipment [Line Items]
Useful life	3 years
Office and other equipment | Maximum
Property, Plant and Equipment [Line Items]
Useful life	20 years

Summary of Significant Accoun39

Summary of Significant Accounting Policies (Schedule of Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014
Reconciliation of beginning and ending carrying amount of AROs [Roll Forward]
Balance	$ 90		$ 43
Accretion expense	9		3
Revision of previous estimate	(50)	[1]	44	[2]
Balance	$ 49		$ 90
[1]	During 2015, we revised our ARO downward by $50 million based on management’s review and assessment of CCR compliance timing and site specific analysis.
[2]	During 2014, we revised our ARO upward by $44 million based on observed trends in Illinois primarily related to CCR surface impoundment closures, groundwater monitoring and updated cost estimates for asbestos in accordance with the standards used in the industry.

Impairments (Details)

Impairments (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Oct. 31, 2013	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Impairment and Other Charges [Line Items]
Impairment and other charges		$ 855	$ 855	$ 0	$ 199
Impairment charge on long-lived assets and related charges					$ 199
Significant Other Unobservable Inputs (Level 3) | Put Option | Elgin, Gibson City and Grand Tower Energy Centers
Impairment and Other Charges [Line Items]
Proceeds from sales of business	$ 138
Coffeen Assets
Impairment and Other Charges [Line Items]
Discount rate		15.00%
Property, Plant, and Equipment, fair value disclosure		$ 0
Impairment and other charges			$ 855

Derivative Financial Instrume41

Derivative Financial Instruments (Details) - USD ($)	Apr. 30, 2008	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative, gain (loss) on derivative, net		$ 0	$ 0	$ 7,000,000
Interest Rate Swap
Derivative [Line Items]
Cash flow hedge gain (loss) reclassified to revenue, amortization period	10 years
Loss amortized over the next 12 months		1,400,000
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent | Interest Rate Swap
Derivative [Line Items]
Accumulated other comprehensive loss, before tax		$ 4,000,000	$ 5,000,000	$ 6,000,000

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule of Fair Value of Receivables and Debt) (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Impairment and other charges		$ 855	$ 855	$ 0	$ 199
Unamortized discount			$ (1)	(1)
Senior Notes Series H 7.00% due 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Stated rate			7.00%
Senior Notes Series I 6.30% due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Stated rate			6.30%
Senior Notes Series F 7.95% due 2032
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Stated rate			7.95%
Significant Other Observable Inputs (Level 2) | Senior Notes Series H 7.00% due 2018 | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value disclosure			$ 300	300
Significant Other Observable Inputs (Level 2) | Senior Notes Series H 7.00% due 2018 | Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value disclosure			204	264
Significant Other Observable Inputs (Level 2) | Senior Notes Series I 6.30% due 2020 | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value disclosure			250	250
Significant Other Observable Inputs (Level 2) | Senior Notes Series I 6.30% due 2020 | Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value disclosure			148	208
Significant Other Observable Inputs (Level 2) | Senior Notes Series F 7.95% due 2032 | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value disclosure	[1]		274	274
Significant Other Observable Inputs (Level 2) | Senior Notes Series F 7.95% due 2032 | Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value disclosure	[1]		162	$ 241
Coffeen Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Impairment and other charges			$ 855
Gas-Fired Facilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Impairment and other charges					$ 199
[1]	Carrying amount includes unamortized discount of $1 million as of December 31, 2015 and 2014. Please read Note 10—Debt for further discussion.

Accumulated Other Comprehensi43

Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning of period		$ (16)	$ (11)	$ (40)
Actuarial gain (loss) and plan amendments (net of tax benefit (expense) of $3, $4, and ($8), respectively)		6	(8)	12
Reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges (net of tax benefit of zero, zero and zero, respectively)	[1]	1	1	1
Settlement loss on pension plan (net of tax benefit of zero, zero and zero, respectively) (2)	[2]	0	2	0
Amortization of unrecognized prior service credit and actuarial loss (net of tax expense of zero, zero, and $1, respectively) (3)	[3]	(1)	0	1
Reclassification of curtailment gain included in net loss (net of tax benefit of zero, zero, and $9, respectively) (4)	[4]	0	0	(13)
Net current period other comprehensive income (loss), net of tax		6	(5)	1
AER Acquisition (net of tax expense of zero, zero, and $20, respectively) (5)	[5]	0	0	28
End of period		(10)	(16)	(11)
Tax benefit (expense) of actuarial gain (loss) and plan amendments		3	4	(8)
Tax of reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges, net	[1]	0	0	0
Tax of settlement loss on pension plan	[2]	0	0	0
Tax expense of amortization of unrecognized prior service credit and actuarial loss	[3]	0	0	1
Tax benefit of reclassification of curtailment gain included in net loss	[4]	0	0	9
Tax expense of the AER Acquisition	[5]	$ 0	$ 0	$ 20
[1]	Amount related to the reclassification of mark-to-market loss on cash flow hedging activities, net and was recorded in Interest expense on our consolidated statements of operations. Please read Note 4—Derivative Financial Instruments for further discussion.
[2]	Amount related to the settlement loss on the EEI pension plan and is included in the computation of total benefit cost (gain). Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.
[3]	Amounts are associated with our defined benefit pension and other post-retirement benefit plans and are included in the computation of net periodic benefit cost (gain). Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.
[4]	Amount related to the EEI curtailment gain on pension and postretirement benefit plans and was recorded in Operating and maintenance expense in our consolidated statements of operations. Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.
[5]	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 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.

Cash Flow Information (Details)

Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Elements [Abstract]
Interest paid (net of amount capitalized)		$ 37	$ 39	$ 41
Income taxes, net				(65)
Non-cash capital expenditures	[1]	$ 0	3	3
Capital contributions from parent			$ 0	$ 72
[1]	These expenditures are primarily for changes in our accruals of capital expenditures for all years presented.

Inventory (Details)

Inventory (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Inventory Disclosure [Abstract]
Materials and supplies	$ 30	$ 30
Coal	102	51
Fuel oil	1	1
Total	$ 133	$ 82

Property, Plant and Equipment46

Property, Plant and Equipment (Schedule of Property and Plant, Net) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 1,750	$ 3,016
Less: Accumulated depreciation and amortization	(813)	(1,145)
Property, plant and equipment, net	937	1,871
Power generation
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,511	2,710
Building and improvements
Property, Plant and Equipment [Line Items]
Property, plant and equipment	212	276
Office and other equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 27	$ 30

Property, Plant and Equipment47

Property, Plant and Equipment (Total Interest Costs Incurred and Interest Costs Capitalized For Construction in Progress) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Abstract]
Impairment	$ 855	$ 855	$ 0	$ 199
Total interest costs incurred		59	59	60
Capitalized interest		$ 22	$ 20	$ 18

Debt (Schedule of Long-Term Deb

Debt (Schedule of Long-Term Debt Outstanding) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt, gross	$ 825	$ 825
Unamortized discount	(1)	(1)
Total long-term debt	824	824
Long-term Debt, Fiscal Year Maturity [Abstract]
2,016	0
2,017	0
2,018	300
2,019	0
2,020	250
Thereafter	$ 275
Senior Notes Series H 7.00% due 2018
Debt Instrument [Line Items]
Stated rate	7.00%
Senior Notes Series H 7.00% due 2018 | Unsecured Debt
Debt Instrument [Line Items]
Debt instrument face amount	$ 300	300
Stated rate	7.00%
Maturity date	2,018
Senior Notes Series I 6.30% due 2020
Debt Instrument [Line Items]
Stated rate	6.30%
Senior Notes Series I 6.30% due 2020 | Unsecured Debt
Debt Instrument [Line Items]
Debt instrument face amount	$ 250	250
Stated rate	6.30%
Maturity date	2,020
Senior Notes Series F 7.95% due 2032
Debt Instrument [Line Items]
Stated rate	7.95%
Senior Notes Series F 7.95% due 2032 | Unsecured Debt
Debt Instrument [Line Items]
Debt instrument face amount	$ 275	$ 275
Stated rate	7.95%
Maturity date	2,032

Debt (Schedule of Required and

Debt (Schedule of Required and Actual Debt Ratios) (Details)	12 Months Ended
	Dec. 31, 2015
Debt Instrument [Line Items]
Covenant compliance, dividend restrictions, interest coverage ratio determination period	1 year
Covenant compliance, dividend restrictions, projected interest coverage ration determination period	2 years
Restricted Payments | Minimum
Debt Instrument [Line Items]
Interest Coverage Ratio	1.75	[1]
Additional Indebtedness | Minimum
Debt Instrument [Line Items]
Interest Coverage Ratio	2.5	[2]
Required debt-to-capital ratio
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.

Related Party Transactions (Nar

Related Party Transactions (Narrative) (Details) - Collateral Agreement with IPM	Dec. 31, 2015USD ($)
Related Party Transaction [Line Items]
Collateral Amount	$ 0
Collateral Amount, Additional Demand	7,500,000
Minimum
Related Party Transaction [Line Items]
Collateral Amount	15,000,000
Maximum
Related Party Transaction [Line Items]
Collateral Amount	$ 22,500,000

Related Party Transactions (Sch

Related Party Transactions (Schedule of Related Party Transactions) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Accounts receivable, affiliates		$ 54	$ 88
Accounts payable, affiliates		18	13
Power supply agreements | Revenues
Related Party Transaction [Line Items]
Operating Revenues		530	646	$ 709
Services provided to AER affiliates | Revenues
Related Party Transaction [Line Items]
Operating Revenues		0	0	6
Ameren Missouri gas transportation agreement | Cost of sales
Related Party Transaction [Line Items]
Operating Expenses		0	0	1
EEI power supply agreement | Cost of sales
Related Party Transaction [Line Items]
Operating Expenses		0	0	66
Services agreement | Operating and maintenance expense
Related Party Transaction [Line Items]
Operating Expenses		34	43	$ 13
Power Supply Agreements | Accounts Receivable, Affiliates
Related Party Transaction [Line Items]
Accounts receivable, affiliates		54	88
Power Supply Agreements | Accounts Payable, Affiliates
Related Party Transaction [Line Items]
Accounts payable, affiliates		0	0
Services Agreement | Accounts Receivable, Affiliates
Related Party Transaction [Line Items]
Accounts receivable, affiliates		0	0
Services Agreement | Accounts Payable, Affiliates
Related Party Transaction [Line Items]
Accounts payable, affiliates		5	1
Tax Sharing Agreement | Accounts Receivable, Affiliates
Related Party Transaction [Line Items]
Accounts receivable, affiliates		0	0
Tax Sharing Agreement | Accounts Payable, Affiliates
Related Party Transaction [Line Items]
Accounts payable, affiliates		3	5
Other Agreements | Accounts Receivable, Affiliates
Related Party Transaction [Line Items]
Accounts receivable, affiliates	[1]	0	0
Other Agreements | Accounts Payable, Affiliates
Related Party Transaction [Line Items]
Accounts payable, affiliates	[1]	10	$ 7
Other Agreements | Accounts Payable, Affiliates | Services provided to AER affiliates
Related Party Transaction [Line Items]
Accounts payable, affiliates		$ 10
[1]	As of December 31, 2015, approximately $10 million of the accounts payable, affiliate balance is comprised of reimbursable employee benefits paid by a Dynegy subsidiary on behalf of Genco.

Income Taxes (Schedule Of Effec

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Income Tax Disclosure [Abstract]
Statutory federal income tax rate:	35.00%	35.00%		35.00%
State tax	5.00%	6.00%		6.00%
Acquisition adjustment	(0.00%)	9.00%	[1]	(15.00%)	[1]
Effective income tax rate	40.00%	50.00%		26.00%
[1]	Acquisition adjustments relating to the impacts of the change in ownership under IRC Section 382 and other tax attribute reductions.

Income Taxes (Schedule Of Compo

Income Taxes (Schedule Of Components Of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Current Federal taxes	$ 0	$ 1	$ 50
Current State taxes	0	0	14
Deferred Federal taxes	305	39	(6)
Deferred State taxes	73	9	6
Deferred investment tax credits, amortization	0	0	1
Total income tax benefit	$ 378	$ 49	$ 65

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities Resulting From Temporary Differences) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Plant related	$ 167	$ 551
Deferred benefit costs	(1)	(6)
ARO	(15)	(36)
NOLs	(25)	(7)
Other	(7)	(9)
Total net accumulated deferred income tax liabilities	$ 119	$ 493

Income Taxes (Schedule Of Chang

Income Taxes (Schedule Of Changes To Unrecognized Tax Benefits And Related Interest) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits	$ 0	$ 0	$ 6
Increases based on tax positions prior to current year	0	0	2
Decreases based on tax positions prior to current year	0	0	(3)
Decreases based on tax positions related to current year	0	0	(1)
Adjustment of balance due to change in ownership	0	0	(3)
Decreases related to the lapse of statute of limitations	0	0	(1)
Unrecognized tax benefits	0	0	0
Total unrecognized tax benefits (detriments) that, if recognized, would affect the effective tax rates	$ 0	$ 0	$ 0

Income Taxes (Reconciliation Of

Income Taxes (Reconciliation Of The Change In The Liability For Interest On Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Liability for interest - beginning of year	$ 0	$ 0	$ 1
Adjustment of balance due to change in ownership	0	0	(1)
Liability for interest - end of year	$ 0	$ 0	$ 0

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Line Items]
Loss before income taxes		$ (941,000,000)	$ (97,000,000)	$ (254,000,000)
State corporate income tax rate		5.00%	6.00%	6.00%
Income tax penalties accrued		$ 0	$ 0	$ 0
Accounts payable, affiliates		(18,000,000)	(13,000,000)
Operating loss carryforwards			0
Income tax credits and adjustments			425,000,000
Adjustments to tax NOLs and other attributes from acquisition			(6,000,000)	(178,000,000)
Operating loss carryforwards, adjustments, income tax benefit			9,000,000	(39,000,000)
Additional Paid-In Capital
Income Taxes [Line Items]
Amounts due to parent under tax sharing agreement		$ (2,000,000)	5,000,000
Adjustments to tax NOLs and other attributes from acquisition			$ (6,000,000)	$ (178,000,000)
Illinois Corporate Income Tax
Income Taxes [Line Items]
State corporate income tax rate		7.75%	9.50%
Forecast | Illinois Corporate Income Tax
Income Taxes [Line Items]
State corporate income tax rate	7.30%
Federal
Income Taxes [Line Items]
Operating loss carryforwards		$ 62,000,000
State
Income Taxes [Line Items]
Operating loss carryforwards		62,000,000
Accounts Payable, Affiliates | Tax Sharing Agreement
Income Taxes [Line Items]
Accounts payable, affiliates		(3,000,000)	$ (5,000,000)
Accounts Payable, Affiliates | Tax Sharing Agreement | Dynegy, Inc.
Income Taxes [Line Items]
Accounts payable, affiliates		$ (3,000,000)	$ (5,000,000)

Commitments and Contingencies (

Commitments and Contingencies (Contingencies) (Details) - complaint	12 Months Ended
	Dec. 31, 2015	May. 31, 2015
Loss Contingencies [Line Items]
Environmental Remediation Obligations, statute of limitations	5 years
MISO 2015-2016 Planning Resource Auction
Loss Contingencies [Line Items]
Loss contingency, number of pending claims		3

Commitments and Contingencies59

Commitments and Contingencies (Commitments) (Details) $ in Millions	Dec. 31, 2015USD ($)
Long-term Purchase Commitment [Line Items]
Expected future payments	$ 4
Illinois Pollution Control Board | Minimum | Newton Facility
Long-term Purchase Commitment [Line Items]
Estimated capital costs to comply with existing and known federal and state air emissions regulations	186
Coal Commitments
Long-term Purchase Commitment [Line Items]
Purchase Obligation	369
Coal Transportation
Long-term Purchase Commitment [Line Items]
Purchase Obligation	$ 407

Savings and Pension and Other60

Savings and Pension and Other Post-Retirement Benefit Plans (Funded Status Of Benefit Plans And Amounts Included In Regulatory Assets And OCI) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 22, 2016
Pension Benefits
Change in benefit obligation:
Benefit obligation, beginning of the year		$ 89	$ 89
Service cost		3	3	$ 5
Interest cost		3	4	10
Actuarial (gain) loss		(3)	7
Benefits paid		(8)	(5)
Plan amendments		0	0
Settlements		0	(9)
Benefit obligation, end of the year		84	89	89
Change in plan assets:
Fair value of plan assets at beginning of year		70	75
Actual return on plan assets		(1)	6
Employer contributions		4	3	15
Benefits paid		(8)	(5)
Settlements		0	(9)
Fair value of plan assets at end of year		65	70	75
Funded status - deficiency		(19)	(19)
Amounts recognized in the balance sheet consist of:
Noncurrent asset	[1]	0	0
Noncurrent liability		(19)	(19)
Net amount recognized		(19)	(19)
Amounts (pretax) recognized in accumulated OCI consist of:
Prior service credit		(2)	(3)
Actuarial loss (gain)		21	20
Net loss recognized		19	17
Pension Benefits | Forecast
Amounts (pretax) recognized in accumulated OCI consist of:
Prior service credit	[2]				$ 0
Actuarial loss (gain)	[2]				1
Net loss recognized	[2]				1
Other Benefits
Change in benefit obligation:
Benefit obligation, beginning of the year		60	50
Service cost		1	1	2
Interest cost		2	2	3
Actuarial (gain) loss		(6)	11
Benefits paid		(3)	(4)
Plan amendments		(8)	0
Settlements		(1)	0
Benefit obligation, end of the year		45	60	50
Change in plan assets:
Fair value of plan assets at beginning of year		68	67
Actual return on plan assets		2	5
Employer contributions		0	0
Benefits paid		(3)	(4)
Settlements		0	0
Fair value of plan assets at end of year		67	68	$ 67
Funded status - deficiency		22	8
Amounts recognized in the balance sheet consist of:
Noncurrent asset	[1]	23	15
Noncurrent liability		(1)	(7)
Net amount recognized		22	8
Amounts (pretax) recognized in accumulated OCI consist of:
Prior service credit		(42)	(39)
Actuarial loss (gain)		42	50
Net loss recognized		$ 0	$ 11
Other Benefits | Forecast
Amounts (pretax) recognized in accumulated OCI consist of:
Prior service credit	[2]				(5)
Actuarial loss (gain)	[2]				3
Net loss recognized	[2]				$ (2)
[1]	The EEI union postretirement plan was over-funded as of December 31, 2015 and 2014 which was included in our balance sheets in “Other assets.”
[2]	Includes only amounts for EEI’s plans.

Savings and Pension and Other61

Savings and Pension and Other Post-Retirement Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Curtailment gain		$ 0	$ 0	$ 26
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost		3	3	5
Interest cost		3	4	10
Expected return on plan assets		(4)	(5)	(13)
Prior service credit		0	0	(1)
Actuarial loss		1	1	6
Net periodic benefit cost		3	3	7
Settlements		0	2	1
Total benefit cost (gain)		3	5	8
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost		1	1	2
Interest cost		2	2	3
Expected return on plan assets		(3)	(3)	(5)
Prior service credit		(5)	(4)	(8)
Actuarial loss		3	3	5
Net periodic benefit cost		(2)	(1)	(3)
Curtailment gain	[1]	0	0	26
Total benefit cost (gain)		$ (2)	$ (1)	$ (29)
[1]	Represents EEI’s management postretirement benefit plans’ curtailment gain recognized due to a reduction of employees as a result of the AER Acquisition.

Savings and Pension and Other62

Savings and Pension and Other Post-Retirement Benefit Plans (Assumptions Used To Determine Benefit Obligations) (Details)		Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate at measurement date	[1]	4.35%	4.00%
Increase in future compensation	[1]	3.50%	3.50%
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate at measurement date	[1]	4.35%	4.00%
Increase in future compensation	[1]	3.50%	3.50%
[1]	A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans at December 31, 2015 and 2014.

Savings and Pension and Other63

Savings and Pension and Other Post-Retirement Benefit Plans (Assumptions Used To Determine Net Periodic Benefit Cost) (Details)		1 Months Ended	11 Months Ended	12 Months Ended
		Dec. 31, 2013	Dec. 02, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	[1]				4.35%	4.00%
Expected return on plan assets	[1]				5.82%	6.16%	7.65%
Rate of compensation increase	[1]				3.50%	3.50%
Pension Benefits | EEI
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.67%	4.00%
Rate of compensation increase		3.50%	5.97%
Pension Benefits | EEI | Forecast
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	[1]			5.90%
Pension Benefits | Ameren
Defined Benefit Plan Disclosure [Line Items]
Discount rate			4.00%
Rate of compensation increase			3.50%
Pension Benefits | Dynegy, Inc. | Forecast
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	[1]			5.60%
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	[1]				4.35%	4.00%
Expected return on plan assets	[1]				5.86%	6.26%	7.59%
Rate of compensation increase	[1]				3.50%	3.50%
Other Benefits | EEI
Defined Benefit Plan Disclosure [Line Items]
Discount rate			4.00%
Other Benefits | EEI | Union Employees
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.00%
Rate of compensation increase		6.35%	6.35%
Other Benefits | EEI | Union Employees | Forecast
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	[1]			6.30%
Other Benefits | EEI | Non-Union Employees | Forecast
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	[1]			5.75%
Other Benefits | EEI | Management
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.75%
Rate of compensation increase		3.50%	3.81%
Other Benefits | Ameren
Defined Benefit Plan Disclosure [Line Items]
Discount rate			4.00%
Rate of compensation increase			3.50%
[1]	A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans for the years ended December 31, 2015 and 2014. A weighted average rate of EEI’s and Ameren’s pension and postretirement plans for the year ended December 31, 2013.

Savings and Pension and Other64

Savings and Pension and Other Post-Retirement Benefit Plans (Assumed Health Care Cost Trend Rates) (Details) - Other Benefits	1 Months Ended	11 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 02, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 01, 2013
Dynegy, Inc.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year			7.00%	7.25%
Ultimate trend rate			4.50%	4.50%
Year that the rate reaches the ultimate trend rate			2,023	2,023
Ameren
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year					5.00%
Ultimate trend rate					5.00%
Year that the rate reaches the ultimate trend rate	2,013				2,013
EEI
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year		7.96%	7.00%	7.25%
Ultimate trend rate			4.50%	4.50%	4.50%
Year that the rate reaches the ultimate trend rate			2,023	2,023		2,027
EEI | Union Employees
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.96%
Year that the rate reaches the ultimate trend rate	2,027				2,027
EEI | Management
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.75%
Year that the rate reaches the ultimate trend rate	2,023				2,023

Savings and Pension and Other65

Savings and Pension and Other Post-Retirement Benefit Plans (Impact of a One Percent Increase/Decrease in Assumed Health Care Cost Trend Rates) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)	[1]
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Aggregate impact on service cost and interest cost, Increase	$ 0
Aggregate impact on service cost and interest cost, Decrease	0
Impact on accumulated post-employment benefit obligation, Increase	6
Impact on accumulated post-employment benefit obligation, Decrease	$ (5)
[1]	Includes amounts only for EEI’s plans.

Savings and Pension and Other66

Savings and Pension and Other Post-Retirement Benefit Plans (Fair Value Of Plan Assets Utilizing Fair Value Hierarchy) (Details) - Pension Benefits - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 65	$ 70	$ 75
EEI
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		130	136
EEI | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1	2
EEI | Equity securities: U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	65	68
EEI | Equity securities: Non-U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]		0
EEI | Equity securities: International
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	12	12
EEI | Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[4]	52	54
EEI | Quoted Prices in Active Markets for Identified Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		54	13
EEI | Quoted Prices in Active Markets for Identified Assets (Level 1) | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1	2
EEI | Quoted Prices in Active Markets for Identified Assets (Level 1) | Equity securities: U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	32	6
EEI | Quoted Prices in Active Markets for Identified Assets (Level 1) | Equity securities: Non-U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]		0
EEI | Quoted Prices in Active Markets for Identified Assets (Level 1) | Equity securities: International
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	7	2
EEI | Quoted Prices in Active Markets for Identified Assets (Level 1) | Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[4]	14	3
EEI | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		76	123
EEI | Significant Other Observable Inputs (Level 2) | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0	0
EEI | Significant Other Observable Inputs (Level 2) | Equity securities: U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	33	62
EEI | Significant Other Observable Inputs (Level 2) | Equity securities: Non-U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]		0
EEI | Significant Other Observable Inputs (Level 2) | Equity securities: International
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	5	10
EEI | Significant Other Observable Inputs (Level 2) | Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[4]	38	51
EEI | Significant Other Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0	0
EEI | Significant Other Unobservable Inputs (Level 3) | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0	0
EEI | Significant Other Unobservable Inputs (Level 3) | Equity securities: U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	0	0
EEI | Significant Other Unobservable Inputs (Level 3) | Equity securities: Non-U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]		0
EEI | Significant Other Unobservable Inputs (Level 3) | Equity securities: International
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	0	0
EEI | Significant Other Unobservable Inputs (Level 3) | Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[4]	$ 0	$ 0
[1]	This category comprises a domestic common collective trust not actively managed that tracks the Dow Jones total U.S. stock market.
[2]	This category comprises a common collective trust not actively managed that tracks the MSCI All Country World Ex-U.S. Index.
[3]	This category comprises actively managed common collective trusts that hold U.S. and foreign equities. These trusts track the MSCI World Index.
[4]	This category includes a mutual fund and a trust that invest primarily in investment grade corporate bonds.

Savings and Pension and Other67

Savings and Pension and Other Post-Retirement Benefit Plans (Cash Contributions Made To Benefit Plans) (Details) - Pension Benefits - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Cash contributions to benefit plans		$ 4	$ 3	$ 15
Allocation
Defined Benefit Plan Disclosure [Line Items]
Cash contributions to benefit plans	[1]	0	0	5
EEI
Defined Benefit Plan Disclosure [Line Items]
Cash contributions to benefit plans		$ 4	$ 3	$ 10
[1]	Represents an allocation of our share of cash contributions associated with our participation in Ameren’s pension plan for the year ended December 31, 2013. There was no allocation of our share of cash contributions associated with our participation in Dynegy’s pension plan for the years ended December 31, 2015 and 2014.

Savings and Pension and Other68

Savings and Pension and Other Post-Retirement Benefit Plans (Schedule Of Expected Payments) (Details) $ in Millions	Dec. 31, 2015USD ($)	[1]
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2,016	$ 8
2,017	7
2,018	7
2,019	7
2,020	6
2021 - 2025	30
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
2,016	2
2,017	2
2,018	2
2,019	2
2,020	2
2021 - 2025	$ 12
[1]	Includes only amounts for EEI’s plans.

Savings and Pension and Other69

Savings and Pension and Other Post-Retirement Benefit Plans (Narrative) (Details) - USD ($) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
		Dec. 31, 2013	Dec. 02, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Retirement Benefits [Line Items]
Curtailment gain on pension and postretirement benefits					$ 0	$ 0	$ (26)
Equity Securities | EEI
Retirement Benefits [Line Items]
Actual plan asset allocations, percent					60.00%
Fixed Income Funds | EEI
Retirement Benefits [Line Items]
Actual plan asset allocations, percent					40.00%
Electric Energy Inc Pension Plan
Retirement Benefits [Line Items]
Estimated future contributions in 2015					$ 4	3
Ameren 401(k) Plan | Ameren
Retirement Benefits [Line Items]
Genco's portion of matching contribution to the Ameren 401(k) plan						1	1
Ameren 401(k) Plan | EEI
Retirement Benefits [Line Items]
Genco's portion of matching contribution to the Ameren 401(k) plan					1
Ameren 401(k) Plan | Dynegy, Inc.
Retirement Benefits [Line Items]
Genco's portion of matching contribution to the Ameren 401(k) plan		$ 0	$ 1		1	1
Pension Benefits
Retirement Benefits [Line Items]
Employer contributions					4	3	15
Estimated pension and postretirement benefit obligations		$ 0			84	89	0
Net periodic benefit cost (less than)					$ 3	$ 3	$ 7
Expected return on plan assets	[1]				5.82%	6.16%	7.65%
Pension Benefits | EEI
Retirement Benefits [Line Items]
Employer contributions					$ 4	$ 3	$ 10
Pension Benefits | EEI | Forecast
Retirement Benefits [Line Items]
Expected return on plan assets	[1]			5.90%
Pension Benefits | Ameren Services
Retirement Benefits [Line Items]
Net periodic benefit cost (less than)			1
Pension Benefits | Dynegy, Inc.
Retirement Benefits [Line Items]
Actual plan asset allocations, amount					2	2
Pension Benefits | Dynegy, Inc. | Forecast
Retirement Benefits [Line Items]
Expected return on plan assets	[1]			5.60%
Other Benefits
Retirement Benefits [Line Items]
Employer contributions					0	0
Curtailment gain on pension and postretirement benefits	[2]				0	0	(26)
Estimated pension and postretirement benefit obligations					45	60
Net periodic benefit cost (less than)					$ (2)	$ (1)	$ (3)
Expected return on plan assets	[1]				5.86%	6.26%	7.59%
Other Benefits | EEI
Retirement Benefits [Line Items]
Employer contributions						$ 1	$ 1
Curtailment gain on pension and postretirement benefits							$ 26
Other Benefits | Ameren Services
Retirement Benefits [Line Items]
Net periodic benefit cost (less than)			$ 1
[1]	A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans for the years ended December 31, 2015 and 2014. A weighted average rate of EEI’s and Ameren’s pension and postretirement plans for the year ended December 31, 2013.
[2]	Represents EEI’s management postretirement benefit plans’ curtailment gain recognized due to a reduction of employees as a result of the AER Acquisition.

Quarterly Financial Informati70

Quarterly Financial Information (Summary Of Quarterly Financial Information) (Details) - USD ($) $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015		Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Selected Quarterly Financial Information [Abstract]
Revenues	$ 114	$ 146		$ 131	$ 143	$ 165	$ 165	$ 138	$ 180	$ 534	$ 648	$ 811
Operating Income (Loss)	(6)	(855)	[1]	(24)	(17)	(7)	(18)	(35)	3	(902)	(57)	(213)
Net loss	(11)	(517)		(19)	(16)	0	(17)	(27)	(4)	(563)	(48)	(189)
Net loss attributable to Illinois Power Generating Company	$ (11)	(519)		$ (17)	$ (15)	$ 0	$ (17)	$ (27)	$ (6)	(562)	(50)	(188)
Impairment and other charges		$ 855								$ 855	$ 0	$ 199
[1]	The results for the three months ended September 30, 2015, include an impairment charge of $855 million. See Note 3—Impairments for more information.