UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June~~September 30, 2015

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________ to ________

Commission file number: 333-56594

ILLINOIS POWER GENERATING COMPANY

(Exact name of registrant as specified in its charter)



State of Incorporation		I.R.S. Employer Identification No.
Illinois		37-1395586

601 Travis, Suite 1400
Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 507-6400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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



Large accelerated filer o		Accelerated filer o
Non-accelerated filer ý		Smaller reporting company o
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of ~~August~~November 10, 2015, there were 2,000 outstanding shares of common stock, without par value, of the registrant, all of which were owned by the registrant’s parent, Illinois Power Resources, LLC, an indirect wholly-owned subsidiary of Dynegy Inc.

OMISSION OF CERTAIN INFORMATION

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

TABLE OF CONTENTS

		Page
DEFINITIONS		i
PART I. FINANCIAL INFORMATION
Item 1.	FINANCIAL STATEMENTS:
	Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	1
	Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014	1
	Consolidated Statements of Operations for the three and six months ended June 30, 2015 and 2014	2
	Consolidated Statements of Operations for the three and nine months ended September 30, 2015 and 2014	2
	Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2015 and 2014	3
	Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2015 and 2014	3
	Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014	4
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014	4
	Notes to Consolidated Financial Statements	5
Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	1415
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	2324
Item 4.	CONTROLS AND PROCEDURES	2324
PART II. OTHER INFORMATION
Item 1.	LEGAL PROCEEDINGS	2425
Item 1A.	RISK FACTORS	2425
Item 6.	EXHIBITS	2425
SIGNATURE		2526

DEFINITIONS

As used in this Form 10-Q, the abbreviations contained herein have the meanings set forth below.

CO2		Carbon Dioxide
CWA		Clean Water Act
EGU		Electric Generating Units
EPA		Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
IMA		In-market Asset Availability
IPCB		Illinois Pollution Control Board
IPH		IPH, LLC (formerly known as Illinois Power Holdings, LLC)
MATS		Mercury and Air Toxics Standards
MISO		Midcontinent Independent System Operator, Inc.
Moody’s		Moody’s Investors Service Inc.
MW		Megawatts
MWh		Megawatt Hour
NM		Not Meaningful
PJM		PJM Interconnection, LLC
PSA		Power Supply Agreement with respect to each of Illinois Power Generating Company and Illinois Power Resources Generating, LLC, or Power Sales Agreement with respect to Electric Energy, Inc.
S&P		Standard & Poor’s Ratings Services



EGU		Electric Generating Units
EPA		Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
IMA		In-market Asset Availability
IPCB		Illinois Pollution Control Board
IPH		IPH, LLC (formerly known as Illinois Power Holdings, LLC)
ISO		Independent System Operator
MISO		Midcontinent Independent System Operator, Inc.
Moody’s		Moody’s Investors Service Inc.
MW		Megawatts
MWh		Megawatt Hour
NM		Not Meaningful
PJM		PJM Interconnection, LLC
PSA		Power Supply Agreement with respect to each of Illinois Power Generating Company and Illinois Power Resources Generating, LLC, or Power Sales Agreement with respect to Electric Energy, Inc.
S&P		Standard & Poor’s Ratings Services

PART I. FINANCIAL INFORMATION

Item 1—FINANCIAL STATEMENTS

ILLINOIS POWER GENERATING COMPANY CONSOLIDATED BALANCE SHEETS(unaudited) (in millions, except share data)
	June 30, 2015			December 31, 2014
	September 30, 2015			December 31, 2014
ASSETS
Current Assets
Cash	$	~~116~~128		$	126
Accounts receivable, affiliates	4341			88
Accounts receivable	165			14
Inventory	9897			82
Deferred income taxes, current	5			5
Deferred income taxes	5			5
Prepayments and other current assets	14			11
Total Current Assets	~~292~~290			326
Property, Plant and Equipment	31,~~044~~783			3,016
Accumulated depreciation	(~~1,195~~802		)	(1,145		)
Property, Plant and Equipment, Net	~~1,849~~981			1,871
Other Assets	2431			24
Total Assets	$	21,~~165~~302		$	2,221
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable	$	2823		$	39
Accounts payable, affiliates	1721			13
Taxes accrued	158			11
Accrued interest	1017			10
Accrued liabilities and other current liabilities	108			10
Total Current Liabilities	8077			83
Long-term debt	824			824
Other Liabilities
Accumulated deferred income taxes, net	474			498
Deferred income taxes, net	132			498
Asset retirement obligations	9597			90
Other long-term liabilities	3122			30
Total Liabilities	1,~~504~~152			1,525
Commitments and Contingencies (Note 8)
Stockholder’s Equity
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding	—			—
Additional paid-in capital	540			540
Accumulated other comprehensive loss, net of tax	(1610		)	(16		)
Retained earnings	~~134~~(385		)	166
Total Illinois Power Generating Company Stockholder’s Equity	~~658~~145			690
Noncontrolling interest	35			6
Total Equity	~~661~~150			696
Total Liabilities and Equity	$	21,~~165~~302		$	2,221

See the notes to consolidated financial statements.

ILLINOIS POWER GENERATING COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions)

	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Revenues	$	~~131~~146		$	~~138~~165		$	~~274~~420		$	~~318~~483
Cost of sales, excluding depreciation expense	(8488		)	(~~105~~121		)	(~~177~~265		)	(~~219~~340		)
Gross margin	4758			3344			97155			99143
Operating and maintenance expense	(4633		)	(4437		)	(88121		)	(83120		)
Depreciation and amortization expense	(25		)	(24		)	(50		)	(48		)
Impairment and other charges	(855		)	—			(855		)	—
Operating loss	(24		)	(35		)	(41		)	(32		)
Depreciation and amortization expense	(25		)	(25		)	(75		)	(73		)
Interest expense	(9		)	(10		)	(19		)	(20		)
Operating loss	(855		)	(18		)	(896		)	(50		)
Loss before income taxes	(33		)	(45		)	(60		)	(52		)
Interest expense	(10		)	(10		)	(29		)	(30		)
Income tax benefit	14			18			25			21
Loss before income taxes	(865		)	(28		)	(925		)	(80		)
Net loss	(19		)	(27		)	(35		)	(31		)
Income tax benefit	348			11			373			32
Less: Net income (loss) attributable to noncontrolling interest	(2		)	—			(3		)	2
Net loss	(517		)	(17		)	(552		)	(48		)
Net loss attributable to Illinois Power Generating Company	$	(17	)	$	(27	)	$	(32	)	$	(33	)
Less: Net income (loss) attributable to noncontrolling interest	2			—			(1		)	2
Net loss attributable to Illinois Power Generating Company	$	(519	)	$	(17	)	$	(551	)	$	(50	)

See the notes to consolidated financial statements.

ILLINOIS POWER GENERATING COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)

	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net loss	$	(19517	)	$	(2717	)	$	(35552	)	$	(3148	)
Other comprehensive loss before reclassifications:
Other comprehensive income (loss) before reclassifications:
Actuarial loss due to pension plan remeasurement (net of tax benefit of zero, zero, zero and $1 million, respectively)	—			—			—			(2		)
Actuarial gain (loss) due to pension plan remeasurement (net of tax benefit of $5, zero, $5 and $1, respectively)	8			—			8			(2		)
Amounts reclassified from accumulated other comprehensive loss:
Settlement loss on pension plan (net of tax benefit of zero and zero, respectively)	—			1			—			2
Reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges (net of tax benefit of zero, zero, zero and zero, respectively)	1			1			1			1
Other comprehensive income, net of tax	—			1			—			—
Settlement loss on pension plan (net of tax benefit of zero and zero, respectively)	—			—			—			2
Comprehensive loss	(19		)	(26		)	(35		)	(31		)
Amortization of unrecognized prior service credit and actuarial loss (net of tax benefit of zero, zero, zero and zero, respectively)	—			(1		)	—			(1		)
Less: Comprehensive income (loss) attributable to noncontrolling interest	(2		)	—			(3		)	2
Other comprehensive income, net of tax	9			—			9			—
Total comprehensive loss attributable to Illinois Power Generating Company	$	(17	)	$	(26	)	$	(32	)	$	(33	)
Comprehensive loss	(508		)	(17		)	(543		)	(48		)
Less: Comprehensive income attributable to noncontrolling interest	3			—			—			2
Total comprehensive loss attributable to Illinois Power Generating Company	$	(511	)	$	(17	)	$	(543	)	$	(50	)

See the notes to consolidated financial statements.

ILLINOIS POWER GENERATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(35552	)	$	(3148	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation expense	50			48
Impairment of long-lived assets	855			—
Deferred income taxes and investment tax credits, net	(24		)	(28		)
Depreciation expense	75			73
Other	5			2
Deferred income taxes and investment tax credits, net	(373		)	(32		)
Other	8			4
Changes in working capital:
Accounts receivable, net	4356			412
Inventory	(1615		)	15
Prepayments and other current assets	(3		)	78
Accounts payable and accrued liabilities	(1		)	1511
Other	1(5		)	—(1		)
Net cash provided by operating activities	2045			1832
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(3043		)	(2636		)
Net cash used in investing activities	(3043		)	(2636		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net cash provided by financing activities	—			—
Net decrease in cash	(10		)	(8		)
Net increase (decrease) in cash	2			(4		)
Cash, beginning of year	126			190
Cash, end of period	$	~~116~~128		$	~~182~~186

See the notes to consolidated financial statements.

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~June~~September 30, 2015 and 2014

Note 1—Basis of Presentation and Organization

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the U.S. Securities and Exchange Commission (“SEC”). The year-end consolidated balance sheet data was derived from audited consolidated financial statements but does not include all disclosures required by Generally Accepted Accounting Principles of the United States of America (“GAAP”). The unaudited consolidated financial statements contained in this report include all material adjustments of a normal recurring nature that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2014, filed with the SEC on March 24, 2015, which we refer to as our “Form 10-K.” 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 an electric generation subsidiary of Illinois Power Resources, LLC (“IPR”), which is an indirect wholly-owned subsidiary of Dynegy Inc. (“Dynegy”). We are headquartered in Houston, Texas and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois 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. All significant intercompany transactions have been eliminated.

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.

Note 2—Accounting Policies

Use of Estimates. The ~~accounting~~preparation ~~policies~~of ~~followed~~consolidated byfinancial ~~the~~statements ~~Company~~in ~~are~~conformity ~~set~~with ~~forth~~GAAP inrequires ~~Note~~management ~~2—Summary~~to make informed estimates and judgments that affect our reported financial position and results of ~~Significant~~operations ~~Accounting~~based ~~Policies~~on currently available information. Actual results could differ materially from our estimates. The results of ~~the~~operations ~~Notes~~for tothe ~~Consolidated~~interim ~~Financial~~periods ~~Statements~~presented in ~~our~~this Form 10-~~K. There~~Q ~~have~~are ~~been~~not nonecessarily ~~significant~~indicative ~~changes~~of the results to ~~these~~be ~~policies~~expected ~~during~~for the ~~six~~full ~~months~~year ~~ended~~or ~~June 30~~any other interim period due to seasonal fluctuations in demand for our energy products and services, ~~2015~~changes in commodity prices, timing of maintenance and other expenditures and other factors.

The ~~preparation~~accounting ofpolicies ~~consolidated~~followed ~~financial~~by ~~statements~~the inCompany ~~conformity~~are ~~with~~set ~~GAAP~~forth ~~requires~~in ~~management~~Note to2—Summary ~~make informed estimates and judgments that affect our reported financial position and results~~ of ~~operations~~Significant ~~based~~Accounting onPolicies ~~currently available information. Actual results could differ materially from our estimates. The results~~ of ~~operations~~the ~~for~~Notes ~~the~~to ~~interim~~Consolidated ~~periods~~Financial ~~presented~~Statements in ~~this~~our Form 10-QK. There ~~are~~have ~~not~~been ~~necessarily~~no ~~indicative~~significant ofchanges ~~the results~~ to bethese ~~expected~~policies ~~for~~during the ~~full~~nine ~~year~~months orended ~~any~~September ~~other interim period due to seasonal fluctuations in demand for our energy products and services~~30, ~~changes in commodity prices, timing of maintenance and other expenditures and other factors~~2015.

Accounting Standards Adopted During the Current Period

~~Reporting Discontinued Operations and Asset Disposals~~Derivatives. In ~~April~~August ~~2014~~2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) ~~2014~~2015-08013-~~Presentation~~Derivatives ~~of Financial Statements (Topic 205)~~ and ~~Property,~~Hedging ~~Plant, and Equipment~~ (Topic ~~360~~815)~~: Reporting Discontinued Operations and Disclosure of Disposals of Components of an Entity~~. The amendments in this ASU ~~change~~specify that the ~~requirements~~use ~~for~~of ~~reporting~~locational ~~discontinued~~marginal ~~operations~~pricing inby ~~Subtopic~~an ~~205-20. An~~ISO ~~entity~~does isnot ~~required~~constitute tonet ~~report~~settlement ~~within~~of ~~discontinued~~a ~~operations~~contract onfor the ~~statement~~purchase ofor ~~operations~~sale ~~the~~of ~~results~~electricity ofon a ~~component~~forward orbasis ~~group~~and, oftherefore, ~~components~~does ofnot ancause ~~entity~~that ifcontract ~~the~~to ~~disposal~~fail ~~represents~~to ameet ~~strategic~~the ~~shift~~physical ~~that~~delivery ~~has,~~criterion orof ~~will~~the ~~have,~~normal apurchases ~~major~~and ~~effect~~normal onsales anscope ~~entity’s operations and financial results~~exception. ~~Additionally,~~If the ~~associated~~physical ~~assets~~delivery ~~and~~criterion ~~liabilities~~is ~~are~~met, ~~required~~along towith beall ~~presented~~of ~~separately~~the ~~from~~ other ~~assets~~criteria ~~and~~of ~~liabilities on~~ the ~~balance~~normal ~~sheet~~purchases ~~for~~and ~~all~~normal ~~comparative~~sales ~~periods. The~~scope ~~ASU~~exception, ~~includes~~an ~~updated~~entity ~~guidance~~may ~~regarding~~elect ~~what~~to ~~meets~~designate ~~the~~that ~~definition~~contract ofas a ~~component~~normal ofpurchase anor ~~entity~~normal sale. The ~~new~~amendments ~~financial~~in ~~statement presentation provisions relating to~~ this ASU are ~~prospective and~~ effective ~~for~~upon ~~interim~~issuance and ~~annual~~should ~~periods~~be ~~beginning~~applied ~~after December 15, 2014, with early adoption permitted~~prospectively. The adoption of this ASU did not have a material impact on our ~~financial~~unaudited ~~statements~~consolidated orfinancial ~~disclosures~~statements.

~~Accounting~~Inventory. In ~~Standards~~July ~~Not~~2015, ~~Yet~~the ~~Adopted~~FASB issued ASU 2015-011-Inventory (Topic 330). The amendments in this ASU require that inventory is measured at the lower of cost and net realizable value (“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 unaudited consolidated financial statements.

Inventory. In July 2015, the FASB issued ASU 2015-011-Inventory (Topic 330). The amendments in this ASU require that inventory is measured at the lower of cost and net realizable value (“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

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~June~~September 30, 2015 and 2014

Retirement Benefits. In April 2015, the FASB issued Accounting Standards Update 2015-04-Compensation-Retirement Benefits (~~NRV~~Topic ~~less~~715). For an entity that has a ~~normal~~significant ~~profit~~event ~~margin)~~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 ~~guidance~~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 ~~this~~the ~~ASU~~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 ~~prospectively~~for public business entities for ~~interim~~financial ~~and~~statements ~~annual~~issued ~~periods~~for fiscal years beginning after December 15, ~~2016~~2015, ~~with~~and ~~early~~interim ~~adoption~~periods ~~permitted. We~~within dothose ~~not~~fiscal ~~anticipate~~years, ~~the~~with early adoption ofallowed. The ~~this~~amendments ~~ASU~~in ~~will~~this ~~have~~Update ashould ~~material~~be ~~impact~~applied onprospectively. We adopted the ~~presentation~~guidance ofin ~~our~~this ~~unaudited~~ASU ~~consolidated~~on ~~financial~~July ~~statements~~1, 2015.

~~Debt~~Reporting ~~Issuance~~Discontinued ~~Costs~~Operations and Asset Disposals. In April ~~2015~~2014, the FASB issued ASU ~~2015~~2014-0308-~~Interest-Imputation~~Presentation of ~~Interest~~Financial Statements (~~Subtopic~~Topic ~~835-30~~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 ~~require~~change ~~that~~the ~~debt~~requirements ~~issuance~~for ~~costs~~reporting ~~related~~discontinued tooperations ain ~~recognized~~Subtopic ~~debt~~205-20. An ~~liability~~entity beis ~~presented~~required into report within discontinued operations on the ~~balance~~statement ~~sheet~~of asoperations the results of a ~~direct~~component ~~deduction~~or ~~from~~group of components of an entity if the ~~carrying~~disposal ~~amount~~represents ofa strategic shift that ~~debt~~has, ~~liability~~or will have, ~~consistent~~a ~~with~~major ~~debt~~effect ~~discounts~~on an entity’s operations and financial results. ~~The~~Additionally, ~~recognition~~the associated assets and ~~measurement~~liabilities ~~guidance~~are ~~for~~required ~~debt~~to ~~issuance~~be ~~costs~~presented ~~are~~separately ~~not~~from ~~affected~~other byassets and liabilities on the ~~amendments~~balance insheet ~~this~~for ~~update~~all comparative periods. The ASU includes updated guidance inregarding what meets the definition of a component of an entity. The new financial statement presentation provisions relating to this ASU isare prospective and effective for interim and annual periods beginning after December 15, ~~2015~~2014, with early adoption permitted. The adoption of this ASU ~~should~~did ~~be applied on a retrospective basis, affecting all balance sheet periods presented. We do~~ not ~~anticipate the adoption of this ASU will~~ have a material impact on ~~the presentation of~~ our ~~consolidated~~financial ~~balance~~statements ~~sheets~~or disclosures.

Accounting Standards Not Yet Adopted

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 should 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 the presentation of our consolidated balance sheets.

Consolidation. In February 2015, the FASB issued ASU 2015-02-Consolidation (Topic 810). The amendments in this ASU respond to concerns about the current accounting for consolidation of certain legal entities, in particular: (i) consolidation of limited partnerships and similar legal entities, (ii) evaluating fees paid to a decision maker or a service provider as a variable interest, (iii) the effect of fee arrangements on the primary beneficiary determination, (iv) the effect of related parties on the primary beneficiary determination, and (v) consolidation of certain investment funds. The guidance in this ASU is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. We do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements.

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 them 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.

Revenue from Contracts with Customers. In May 2014, the FASB and International Accounting Standards Board (“IASB”) jointly issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). The amendments in this ASU develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards (“IFRS”) 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.6

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2015 and 2014

Revenue from Contracts with Customers. In May 2014, the FASB and International Accounting Standards Board (“IASB”) 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 U.S. GAAP and International Financial Reporting Standards (“IFRS”) 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.

Note 3—Risk Management, Derivatives and Financial Instruments

We did not have a material amount of derivative instruments as of ~~June~~September 30, 2015 and December 31, 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 and $5 million as of ~~June~~September 30, 2015 and December 31, 2014, respectively. These interest rate swaps were executed in 2007 as a partial hedge of interest rate risks associated with our April 2008 debt issuance. The loss on the interest rate swaps is being amortized out of AOCI into our consolidated statements of operations over a 10-year period that began in April 2008, $1.4 million of which will be amortized in 2015.

Financial Instruments Not Designated as Hedges. There was no material impact of mark-to-market gains (losses) on our unaudited consolidated statements of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2015 and 2014.

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2015 and 2014

Note 4—Fair Value Measurements

Non-recurring Measurements. During the third quarter of 2015, several final environmental regulations were enacted 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 that mixes out-of-state regulated generators that receive rate based compensation from their home states to recover costs, with Central and Southern Illinois competitive generators that rely on the capacity market for fair compensation to recover costs. The results of this analysis determined the book value of the Coffeen facility was not recoverable, requiring the facility to be impaired. We conducted a 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 in Impairments and other charges in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2015. The valuation is classified as Level 3 within the fair value hierarchy levels.

Fair Value of Financial Instruments. We have determined the 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.

6The 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 September 30, 2015 and December 31, 2014, respectively. All fair values presented below are classified within Level 2 of the fair value hierarchy.



	September 30, 2015				December 31, 2014
(amounts in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
7.00% Senior Notes Series H, due 2018	$	300	$	275	$	300	$	264
6.30% Senior Notes Series I, due 2020	$	250	$	209	$	250	$	208
7.95% Senior Notes Series F, due 2032 (1)	$	274	$	235	$	274	$	241

__________________________________________


(1)	Carrying amount includes unamortized discount of $1 million as of September 30, 2015 and December 31, 2014. Please read Note 7—Debt for further discussion.

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~June~~September 30, 2015 and 2014

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 June 30, 2015 and December 31, 2014, respectively. All fair values presented below are classified within Level 2 of the fair value hierarchy.

	June 30, 2015				December 31, 2014
(amounts in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
7.95% Senior Notes Series F, due 2032 (1)	$	274	$	257	$	274	$	241
7.00% Senior Notes Series H, due 2018	$	300	$	290	$	300	$	264
6.30% Senior Notes Series I, due 2020	$	250	$	229	$	250	$	208

__________________________________________

(1) Carrying amount includes unamortized discount of $1 million as of June 30, 2015 and December 31, 2014. Please read Note 7—Debt for further discussion.

Note 5—Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss), net of tax, by component are as follows:

	Six Months Ended June 30,
	Nine Months Ended September 30,
(amounts in millions)	2015			2014
Beginning of period	$	(16	)	$	(11	)
Other comprehensive loss before reclassifications:
Other comprehensive income (loss) before reclassifications:
Actuarial loss due to pension plan remeasurement (net of tax benefit of zero and $1 million, respectively)	—			(2		)
Actuarial gain (loss) due to pension plan remeasurement (net of tax benefit of $5 and $1, respectively)	5			(2		)
Amounts reclassified from accumulated other comprehensive loss:
Settlement loss on pension plan (net of tax benefit of zero and zero, respectively) (1)	—			2
Reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges (net of tax benefit of zero and zero, respectively) (1)	1			1
Net current period other comprehensive loss, net of tax	—			—
Settlement loss on pension plan (net of tax benefit of zero and zero, respectively) (2)	—			2
End of period	$	(16	)	$	(11	)
Amortization of unrecognized prior service credit and actuarial loss (net of tax benefit of zero and zero, respectively) (3)	—			(1		)
Net current period other comprehensive income, net of tax	6			—
End of period	$	(10	)	$	(11	)

_______________________________________

(1) Amount related to the ~~settlement~~reclassification ~~loss~~of mark-to-market losses on ~~the~~cash ~~EEI~~flow ~~pension~~hedging ~~plan~~activities and iswas ~~included~~recorded in ~~the~~Interest ~~computation~~expense ofon ~~total~~our ~~benefit~~unaudited ~~cost~~consolidated ~~(gain)~~statements of operations. Please read Note 113—~~Pension~~Risk ~~and~~Management, ~~Other~~Derivatives ~~Post-Employment~~and ~~Benefits~~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 11—Pension and Other Post-Employment Benefits for further discussion.


(3)	Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic benefit cost (gain). Please read Note 11—Pension and Other Post-Employment Benefits for further discussion.

Note 6—Inventory

A summary of our inventories is as follows:

(amounts in millions)	~~June~~September 30, 2015		December 31, 2014
Materials and supplies	$	30	$	30
Coal	6766		51
Fuel oil	1		1
Total	$	9897	$	82

Note 7—Debt

A summary of our long-term debt is as follows:



(amounts in millions)	September 30, 2015			December 31, 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

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~June~~September 30, 2015 and 2014

Note 7—Debt

A summary of our long-term debt is as follows:

(amounts in millions)	June 30, 2015			December 31, 2014
Unsecured notes:
7.95% Senior Notes Series F, due 2032	$	275		$	275
7.00% Senior Notes Series H, due 2018	300			300
6.30% Senior Notes Series I, due 2020	250			250
	825			825
Unamortized discount	(1		)	(1		)
Total Long-term debt	$	824		$	824

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 ~~June~~September 30, 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:~~

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 a 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.

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

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 ~~June~~September 30, 2015 calculations, our interest coverage ratios are less than the minimum ratios required to pay dividends and borrow additional funds from external, third-party sources. As a result, we were restricted from paying dividends as of ~~June~~September 30, 2015.

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

Note 8—Commitments and Contingencies

Contingencies

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. Management assesses matters based on current information and makes 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 any legal proceedings could involve amounts that are different from recorded accruals and that such differences could be material.

We are party to 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.

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, Inc., 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

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~June~~September 30, 2015 and 2014

~~Note~~Market ~~8—Commitments~~Monitor for MISO (“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and ~~Contingencies~~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.

~~Contingencies~~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.

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. Management assesses matters based on current information and makes 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 any new information with respect to such contingencies and adjusts its assessment 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 any legal proceedings could involve amounts that are different from recorded accruals and that such differences could be material.

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.

MISO 2015-2016 Planning Resource Auction Complaints. In May of 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, Inc., 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 an 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.

New Source Review and Clean Air Litigation. Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the 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 ~~our~~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 ~~our~~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 ~~our~~the ~~Newton facility~~ NOV.

Ultimate resolution 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. Hydrogeologic investigations of the coal combustion residuals (“CCR”) surface impoundments have been performed at the Newton, Coffeen and Joppa facilities. Groundwater monitoring results indicate that the CCR surface impoundments at each of ~~our~~the facilities potentially impact onsite groundwater.

In 2012, the Illinois EPA issued violation notices with respect to groundwater conditions at our Newton and Coffeen facilities’ CCR surface impoundments. In February 2013, the Illinois EPA provided written notice that it may pursue legal action with respect to each of these matters through referral to the Illinois Office of the Attorney General. In addition, 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.

9In April 2013, Ameren Energy Resources Company filed a proposed site-specific rulemaking with the IPCB which, if approved, would provide for the systematic and eventual closure of our CCR surface impoundments that impact groundwater in exceedance of applicable groundwater standards. In October 2013, the Illinois EPA filed a proposed rulemaking with the IPCB that would establish processes governing monitoring, corrective action and closure of CCR surface impoundments at all power generating facilities in Illinois. The Illinois EPA’s proposed rulemaking has been stayed to consider the implications of the federal EPA’s CCR rule. The site-specific rulemaking proposal also has been stayed. In November 2015, the IPCB extended the stay of the Illinois EPA’s proposed rulemaking until early March 2016, at which time the Illinois EPA is required to provide a status report.

At this time, we cannot reasonably estimate the costs or range of costs of resolving our Newton, Coffeen and Joppa groundwater matters, but resolution of these matters may cause us to incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows.

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~June~~September 30, 2015 and 2014

the likely source of the contamination and recommends various measures to minimize the effects of that source on the groundwater monitoring results of the active landfill.

In April 2013, Ameren Energy Resources Company filed a proposed site-specific rulemaking with the IPCB which, if approved, would provide for the systematic and eventual closure of its CCR surface impoundments that impact groundwater in exceedance of applicable groundwater standards. In October 2013, the Illinois EPA filed a proposed rulemaking with the IPCB that would establish processes governing monitoring, corrective action and closure of CCR surface impoundments at all power generating facilities in Illinois. The site-specific rulemaking proposal, which now covers IPH, including Genco, CCR surface impoundments, has been stayed to allow the Illinois EPA proposed rulemaking to proceed. In May 2015, the IPCB granted the Illinois EPA’s request for a 90-day stay of its proposed rulemaking to consider the implications of the EPA final CCR rule.

At this time we cannot reasonably estimate the costs or range of costs of resolving our Newton, Coffeen and Joppa groundwater matters, but resolution of these matters may cause us to incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows.

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.

Coal Transportation. During the ~~six~~nine months ended ~~June~~September 30, 2015, we executed one new long-term coal transportation contract with an aggregate commitment of $175 million. Under this contract, we have the ability to terminate our obligation beginning in the year 2021, which would reduce our commitment to $62 million.

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, ~~in most cases~~ management considers the probability of loss to be remote.

Guaranty

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.

Note 9—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, and services received or rendered. For a discussion of our material related party agreements, please read Note 11—Related Party Transactions of the Form 10-K.

The following table summarizes the affiliate accounts receivable and payable on our unaudited consolidated balance sheets.



	September 30, 2015				December 31, 2014
(amounts in millions)	Accounts Receivable, Affiliates		Accounts Payable, Affiliates		Accounts Receivable, Affiliates		Accounts Payable, Affiliates
Power supply agreements	$	41	$	—	$	88	$	—
Services agreement	—		5		—		1
Tax sharing agreement	—		6		—		5
Other (1)	—		10		—		7
Total	$	41	$	21	$	88	$	13

__________________________________________


(1)	At September 30, 2015 and December 31, 2014, approximately $8 million and $5 million, respectively, of the accounts payable, affiliate balance is comprised of reimbursable employee benefits paid by a Dynegy subsidiary on behalf of Genco.

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~June~~September 30, 2015 and 2014

	June 30, 2015				December 31, 2014
(amounts in millions)	Accounts Receivable, Affiliates		Accounts Payable, Affiliates		Accounts Receivable, Affiliates		Accounts Payable, Affiliates
Power supply agreements	$	43	$	—	$	88	$	—
Services agreement	—		3		—		1
Tax sharing agreement	—		5		—		5
Other (1)	—		9		—		7
Total	$	43	$	17	$	88	$	13

The following table presents the impact of related party transactions on our unaudited consolidated statements of operations for the three and nine months ended September 30, 2015 and 2014. It is based primarily on the agreements discussed below and in Note 11—Related Party Transactions of the Form 10-K.

__________________________________________



		Three Months Ended September 30,				Nine Months Ended September 30,
(amounts in millions)	Income Statement Line Item	2015		2014		2015		2014
Power supply agreements	Revenues	$	146	$	162	$	418	$	480
Services agreement	Operating and maintenance expense	$	7	$	10	$	26	$	31

(1) At June 30, 2015 and December 31, 2014, approximately $7 million and $5 million, respectively, 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 unaudited consolidated statements of operations for the three and six months ended June 30, 2015 and 2014. It is based primarily on the agreements discussed below and in Note 11—Related Party Transactions of the Form 10-K.

		Three Months Ended June 30,				Six Months Ended June 30,
(amounts in millions)	Income Statement Line Item	2015		2014		2015		2014
Power supply agreements	Revenues	$	130	$	137	$	273	$	317
Services agreement	Operating and maintenance expense	$	8	$	11	$	19	$	21

Power Supply Agreements

Genco has a PSA with Illinois Power Marketing Company (“IPM”), a subsidiary of IPR, whereby Genco agreed to sell and IPM agreed to purchase 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 ~~are~~ 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 EEI agreed to sell and IPM agreed to purchase all of the capacity and energy available from EEI’s generation fleet. ~~The~~With limited exceptions, the price that IPM pays for capacity is ~~set~~the ~~annually~~MISO ~~based~~Local ~~upon~~Resources ~~prevailing~~Zone ~~market~~4 ~~prices~~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 service agreements. Prior to the beginning of each fiscal year in which Services are to be provided pursuant to the Service Agreements, the Providers and the Recipients agree on a budget for the Services, outlining, among other items, the contemplated scope of the Services to be provided in the following fiscal year and the cost of providing the Services. The Recipients will pay the Providers an annual management fee as agreed in the budget. We believe this 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.

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2015 and 2014

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 at December 31, 2014 and provides that accumulated taxes payable to Dynegy, and any associated interest, be settled at the discretion of Dynegy or us.

Note 10—Income Taxes

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, ~~except~~including ~~for~~our ~~significant~~impairment ~~unusual~~loss orof ~~extraordinary~~$855 ~~transactions~~million. ~~Income~~ ~~taxes~~Please ~~for~~read ~~significant~~Note ~~unusual~~4—Fair orValue ~~extraordinary~~Measurements ~~transactions are computed and recorded in the period that the specific transaction occurs.~~

~~Note 11—Pension and Other Post-Employment Benefits~~13

We offer defined benefit pension and other post-employment benefit plans covering our employees. Separately, our EEI employees and retirees participate in EEI’s single-employer pension and other post-employment plans. We consolidate EEI; therefore, EEI’s plans are reflected in our pension and other post-employment balances and disclosures. Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans in our Form 10-K for further discussion.

Components of Net Periodic Benefit Cost (Gain). The following table presents the components of our net periodic benefit cost of the EEI pension and other post-employment benefit plans for the three and six months ended June 30, 2015 and 2014. Also reflected is an allocation of net periodic benefit costs from our participation in Dynegy’s single-employer pension and other post-employment plans for the three and six months ended June 30, 2015 and 2014.

	Pension Benefits						Other Benefits
	Three Months Ended June 30,
(amounts in millions)	2015			2014			2015			2014
Service cost	$	—		$	—		$	1		$	—
Interest cost	1			1			—			—
Expected return on plan assets	(1		)	(1		)	(1		)	(1		)
Amortization of:
Prior service credit	—			—			—			(1		)
Actuarial loss	—			—			—			1
Net periodic benefit (gain)	—			—			—			(1		)
Settlements	—			1			—			—
Total benefit cost (gain)	$	—		$	1		$	—		$	(1	)

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~June~~September 30, 2015 and 2014

	Pension Benefits						Other Benefits
	Six Months Ended June 30,
(amounts in millions)	2015			2014			2015			2014
Service cost	$	1		$	1		$	1		$	—
Interest cost	2			2			1			1
Expected return on plan assets	(2		)	(2		)	(2		)	(2		)
Amortization of:
Prior service credit	—			—			—			(2		)
Actuarial loss	—			—			—			2
Net periodic benefit cost (gain)	1			1			—			(1		)
Settlements	—			2			—			—
Total benefit cost (gain)	$	1		$	3		$	—		$	(1	)

for further details. Income taxes for significant unusual or extraordinary transactions are computed and recorded in the period that the specific transaction occurs.

13Note 11—Pension and Other Post-Employment Benefits

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 using inputs as of July 31, 2015. We recorded a gain through accumulated other comprehensive loss and decreased our net liability by approximately $13 million during the third quarter of 2015.

Components of Net Periodic Benefit Cost (Gain). The following table presents the components of our net periodic benefit cost (gain) of the EEI pension and other post-employment benefit plans for the three and nine months ended September 30, 2015 and 2014. Also reflected is an allocation of net periodic benefit costs (gain) from our participation in Dynegy’s single-employer pension and other post-employment plans for the three and nine months ended September 30, 2015 and 2014.



	Pension Benefits						Other Benefits
	Three Months Ended September 30,
(amounts in millions)	2015			2014			2015			2014
Service cost	$	1		$	1		$	—		$	1
Interest cost	—			1			1			1
Expected return on plan assets	(1		)	(1		)	(1		)	(1		)
Amortization of:
Prior service credit	1			—			(1		)	(1		)
Actuarial loss	—			—			—			—
Net periodic benefit cost (gain)	1			1			(1		)	—
Total benefit cost (gain)	$	1		$	1		$	(1	)	$	—



	Pension Benefits						Other Benefits
	Nine Months Ended September 30,
(amounts in millions)	2015			2014			2015			2014
Service cost	$	2		$	2		$	1		$	1
Interest cost	2			3			2			2
Expected return on plan assets	(3		)	(3		)	(3		)	(3		)
Amortization of:
Prior service credit	1			—			(1		)	(3		)
Actuarial loss	—			—			—			2
Net periodic benefit cost (gain)	2			2			(1		)	(1		)
Settlements	—			2			—			—
Total benefit cost (gain)	$	2		$	4		$	(1	)	$	(1	)

ILLINOIS POWER GENERATING COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended ~~June~~September 30, 2015 and 2014

Item 2—MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read together with the unaudited consolidated financial statements and the notes thereto included in this report and with the audited consolidated financial statements and the notes thereto included in our Form 10-K.

We are an electric generation subsidiary of Illinois Power Resources, LLC, which is an indirect wholly-owned subsidiary of Dynegy. We own and operate a merchant generation business in Illinois. Our current business operations are focused primarily on the unregulated power generation sector of the energy industry.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In this section, we describe our liquidity and capital requirements including our sources and uses of liquidity and capital resources. Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements and contractual obligations, capital expenditures (including required environmental expenditures) and working capital needs. Examples of working capital needs include purchases and sales of commodities and associated margin and collateral requirements, facility maintenance costs and other costs such as payroll. Our primary sources of liquidity are cash flows from operations and cash on hand.

At ~~June~~September 30, 2015, our liquidity consisted of $~~116~~128 million of cash on hand. Due to the ring-fenced nature of IPH and Genco, cash at the IPH and Genco entities may not be moved out of these entities without meeting certain criteria. However, cash at these entities is available to support current operations of these entities. Based on current projections as of ~~June~~September 30, 2015, we expect ~~operating cash flows and~~ daily working capital needs and capital expenditures to be sufficiently covered by our operating cash flows and cash on hand inthrough ~~2015~~2016.

The following table presents net cash from operating, investing and financing activities for the ~~six~~nine months ended ~~June~~September 30, 2015 and 2014:

	Six Months Ended June 30,
	Nine Months Ended September 30,
(amounts in millions)	2015			2014
Net cash provided by operating activities	$	2045		$	1832
Net cash used in investing activities	$	(3043	)	$	(2636	)
Net cash provided by financing activities	$	—		$	—

Operating Activities

Historical Operating Cash Flows. Cash provided by operations totaled $2045 million for the ~~six~~nine months ended ~~June~~September 30, 2015. During the period, our power generation business provided cash of $3867 million primarily due to the operation of our power generation facilities and approximately $1115 million of cash ~~was provided~~ related to changes in working capital, offset by $2937 million in interest payments.

Cash provided by operations totaled $18 million for the six months ended June 30, 2014. During the period, we had sources of $35 million primarily due to the operation of our power generation facilities and approximately $12 million in positive 15

14Cash provided by operations totaled $32 million for the nine months ended September 30, 2014. During the period, we had sources of $48 million primarily due to the operation of our power generation facilities and approximately $13 million in positive changes in working capital, net of $4 million of increased collateral postings to satisfy our counterparty collateral demands, offset by $29 million in interest payments.

~~changes~~Future inOperating ~~working~~Cash ~~capital~~Flows. Our future operating cash flows will vary based on a number of factors, ~~net~~many of $4which ~~million~~are beyond our control, including the price of ~~increased~~power, ~~collateral~~the ~~postings~~prices toof ~~satisfy~~coal ~~our~~and ~~counterparty~~their correlation to power prices, collateral ~~demands~~requirements, ~~offset~~the byvalue ~~$29~~of ~~million~~capacity inand ~~interest~~ancillary ~~payments~~services, the run time of our generating facilities, the effectiveness of our commercial strategy and legal requirements.

~~Future~~Collateral ~~Operating~~Postings. We ~~Cash~~use ~~Flows. Our~~a ~~future~~portion ~~operating~~of our capital resources in the form of cash ~~flows~~and ~~will~~lines ~~vary~~of ~~based~~credit onto satisfy counterparty collateral demands. Our collateral postings to third parties consisted of a ~~number~~$5 million line of ~~factors~~credit at September 30, ~~many~~2015 and $5 million of ~~which~~cash ~~are~~at ~~beyond~~December 31, ~~our~~2014. On ~~control~~February 26, ~~including~~2014, ~~the~~Genco ~~price~~entered ofinto ~~power~~a collateral agreement, ~~the~~with ~~prices~~a total limit not to exceed $22.5 million, with Illinois Power Marketing Company (“IPM”) pursuant to which Genco may provide collateral to IPM to secure obligations of ~~coal~~IPM ~~and~~applicable ~~their~~to ~~correlation~~Genco’s assets. We have provided no amounts to ~~power~~IPM ~~prices~~under this agreement as of September 30, 2015. Additional collateral ~~requirements~~support for agreements entered into prior to December 2, ~~the~~2013 ~~value~~will ofcontinue ~~capacity~~to ~~and~~be ~~ancillary~~provided ~~services~~by Ameren Corporation (“Ameren”) through December 2, ~~the~~2015, ~~run~~after ~~time~~which Genco may be called upon to post collateral through its collateral posting agreement with IPM described above. As of ~~our~~September ~~generating~~30, ~~facilities~~2015, the ~~effectiveness~~amount of ~~our~~collateral ~~commercial~~posted ~~strategy~~by ~~and~~Ameren ~~legal,~~was ~~environmental~~$12 ~~and regulatory requirements~~million.

Collateral Postings. We use a portion of our capital resources in the form of cash to satisfy counterparty collateral demands. Our collateral postings to third parties were $5 million at June 30, 2015 and December 31, 2014. On February 26, 2014, Genco entered into a collateral agreement with Illinois Power Marketing Company (“IPM”) pursuant to which Genco may provide collateral to IPM to secure obligations of IPM applicable to Genco’s assets. We have provided no amounts to IPM under this agreement as of June 30, 2015. Additional collateral support for agreements entered into prior to December 2, 2013 will continue to be provided by Ameren Corporation through December 2, 2015, after which Genco may be called upon to post collateral through its collateral posting agreement with IPM described above.

Investing Activities

Capital Expenditures. We had capital expenditures of approximately $3043 million and $2636 million during the ~~six~~nine months ended ~~June~~September 30, 2015 and 2014, respectively. These amounts included capitalized interest of $1116 million and $1015 million for the ~~six~~nine months ended ~~June~~September 30, 2015 and 2014, respectively.

Financing Activities

Historical Cash Flow from Financing Activities. During each of the ~~six~~nine months ended ~~June~~September 30, 2015 and 2014, we had no cash flow from financing activities.

Financing Trigger Events. 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. We do not have any trigger events tied to specified credit ratings or stock price in our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events.

Financial Covenant. Our indenture includes provisions that require us to maintain certain interest coverage and debt-to-capital ratios for us to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans or investments in affiliates or to incur additional external, third-party indebtedness.

The following table summarizes these required ratios as of and for the three months ended ~~June~~September 30, 2015:

	Required Ratio	Actual Ratio
Restricted payment interest coverage ratio (1)	≥1.75	1.9238
Additional indebtedness interest coverage ratio (2)	≥2.50	1.9238
Additional indebtedness debt-to-capital ratio (2)	≤60%	5684%

__________________________________________


(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.

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

Based on ~~June~~September 30, 2015 calculations, our interest coverage ratios are less than the minimum ratios required for us to borrow additional funds from external, third-party sources.

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

Dividends

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 ~~June~~September 30, 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 ~~June~~September 30, 2015. Please read Note 7—Debt for further discussion on indenture provisions. ~~We paid no dividends in 2015 or 2014.~~

Credit Ratings

In carrying out our commercial business strategy, our current non-investment grade credit ratings have resulted and may result in requirements that we either prepay obligations or post collateral to support our business.

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



	Moody’s	S&P
Issuer/Corporate	B3	CCC+
Senior Unsecured	B3	CCC+

1617

RESULTS OF OPERATIONS

Overview

In this section, we discuss our results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2015 and 2014. Our results of operations and financial position are affected by many factors. Weather, economic conditions and the actions of key customers or competitors can significantly affect the demand for our services. At the end of this section, we have included our business outlook.

Genco has a PSA with IPM, a subsidiary of IPR, whereby it agreed to sell and IPM agreed to purchase all of the capacity and energy available from its generation fleet. IPM entered into a similar PSA with Illinois Power Resources Generating, LLC (“IPRG”). Under the PSAs, IPM revenues are allocated between Genco and IPRG ~~are~~ 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. Additionally, the revenues allocated include settled values of derivative instruments entered into by IPM to hedge commodity exposure related to Genco and IPRG generation.

Electric Energy, Inc. (“EEI”) has a PSA with IPM, whereby EEI agreed to sell and IPM agreed to purchase all of the capacity and energy available from EEI’s generation fleet. ~~The~~With limited exceptions, the price that IPM pays for capacity is ~~set~~the ~~annually~~MISO ~~based~~Local ~~upon~~Resources ~~prevailing~~Zone ~~market~~4 ~~prices~~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.

Ultimately, our sales are subject to market conditions for power. We principally use coal and limited amounts of natural gas for fuel in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply, demand and many other factors. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. As discussed above, IPM may hedge exposures related to our generation through derivative contracts and the settled value under those contracts are allocated to us through the PSAs. The reliability of our facilities, operations and maintenance costs and capital ~~investment~~expenditures are key factors that we seek to control in order to optimize our results of operations, financial position and liquidity.

17During the third quarter of 2015, several final environmental regulations were enacted 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 that mixes out-of-state regulated generators that receive rate based compensation from their home states to recover costs, with Central and Southern Illinois competitive generators that rely on the capacity market for fair compensation to recover costs. The results of this analysis determined the book value of the Coffeen facility was not recoverable, requiring the facility to be impaired. We conducted a 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 in Impairments and other charges in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2015.

~~Consolidated Summary Financial Information — Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014~~ 18

~~The~~Consolidated ~~following~~Summary ~~table~~Financial ~~provides~~Information ~~summary~~— ~~financial~~Three ~~data~~Months ~~regarding~~Ended ~~our~~September ~~consolidated~~30, ~~results~~2015 ofCompared ~~operations~~to ~~for~~Three ~~the~~Months ~~three~~Ended ~~months~~September ~~ended June~~ 30, ~~2015 and~~ 2014, ~~respectively:~~

	Three Months Ended June 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2015			2014
Revenues	$	131		$	138		$	(7	)	(5	)%
Cost of sales, excluding depreciation expense	(84		)	(105		)	21			20	%
Gross margin	47			33			14			42	%
Operating and maintenance expense	(46		)	(44		)	(2		)	(5	)%
Depreciation and amortization expense	(25		)	(24		)	(1		)	(4	)%
Operating loss	(24		)	(35		)	11			31	%
Interest expense	(9		)	(10		)	1			10	%
Loss before income taxes	(33		)	(45		)	12			27	%
Income tax benefit	14			18			(4		)	22	%
Net loss	(19		)	(27		)	8			30	%
Less: Net loss attributable to noncontrolling interest	(2		)	—			(2		)	(100	)%
Net loss attributable to Illinois Power Generating Company	$	(17	)	$	(27	)	$	10		(37	)%
Million Megawatt Hours Generated	3.6			4.3			(0.7		)	(16	)%
IMA for Genco Facilities (1)	92		%	89		%
Average Capacity Factor for Genco Facilities (2)	53		%	63		%
Average Power Prices ($/MWh) (3)	$	36.04		$	32.77		$	3.27		10	%

The following table provides summary financial data regarding our consolidated results of operations for the three months ended September 30, 2015 and 2014, respectively:



	Three Months Ended September 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
(amounts in millions)	2015			2014			Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Revenues	$	146		$	165		$	(19	)	(12	)%
Cost of sales, excluding depreciation expense	(88		)	(121		)	33			27	%
Gross margin	58			44			14			32	%
Operating and maintenance expense	(33		)	(37		)	4			11	%
Impairment and other charges	(855		)	—			(855		)	(100	)%
Depreciation and amortization expense	(25		)	(25		)	—			—	%
Operating loss	(855		)	(18		)	(837		)	NM
Interest expense	(10		)	(10		)	—			—	%
Loss before income taxes	(865		)	(28		)	(837		)	NM
Income tax benefit	348			11			337			NM
Net loss	(517		)	(17		)	(500		)	NM
Less: Net income attributable to noncontrolling interest	2			—			2			100	%
Net loss attributable to Illinois Power Generating Company	$	(519	)	$	(17	)	$	(502	)	NM

Million Megawatt Hours Generated	3.7			5.2			(1.5		)	(29	)%
IMA for Genco Facilities (1)	89		%	94		%
Average Capacity Factor for Genco Facilities (2)	55		%	77		%
Average Quoted Market Power Prices ($/MWh) (3)
On-Peak: Indiana (Indy Hub)	$	33.09		$	37.90		$	(4.81	)	(13	)%
Off-Peak: Indiana (Indy Hub)	$	23.37		$	27.57		$	(4.20	)	(15	)%

________________________________________


(1)	IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. This calculation excludes certain events outside of management control such as weather related issues.


(2)	Reflects actual production as a percentage of available capacity.

(3) Reflects the average ~~price~~of ~~calculated~~day-ahead ~~from~~quoted ~~the~~prices ~~revenues~~for ~~allocated to Genco from IPM per~~ the ~~PSAs.~~periods ~~See~~presented ~~Note~~and ~~9—Related~~does ~~Party~~not ~~Transactions~~necessarily ~~for~~reflect ~~further~~prices ~~discussion~~we realized.

Discussion of Consolidated Results of Operations

Revenues. Revenues decreased by $719 million from $~~138~~165 million for the three months ended ~~June~~September 30, 2014 to $~~131~~146 million for the three months ended ~~June~~September 30, 2015. The decrease is due to ~~$20 million in~~ lower energy revenues received through the PSAs asrelated ~~the~~to ~~result of~~ lower ~~sales~~market ~~volumes~~prices ~~primarily~~as ~~related to~~ a ~~outages~~result atof ~~EEI~~milder weather, which was offset by anincreased ~~increase~~capacity ofrevenue ~~$13~~received ~~million~~through ~~from~~the aPSAs from higher ~~price~~capacity ~~per~~clearing ~~MWh~~prices ~~during~~for the three months ended ~~June~~September 30, 2015. compared to the three months ended September 30, 2014.

Cost of Sales. Cost of sales decreased by $2133 million from $~~105~~121 million for the three months ended ~~June~~September 30, 2014 to $8488 million for the three months ended ~~June~~September 30, 2015. The decrease is primarily due to ~~$15~~lower ~~million~~coal inand ~~lower~~coal ~~generation~~transportation ~~volumes~~costs ~~and~~due $6to ~~million~~less ingeneration ~~lower~~as ~~fuel~~a ~~prices~~result of milder weather during the three months ended ~~June~~September 30, 2015.

Operating and Maintenance Expense. Operating and maintenance expense ~~increased~~decreased by $24 million from $4437 million for the three months ended ~~June~~September 30, 2014 to $4633 million for the three months ended ~~June~~September 30, 2015~~. The~~, ~~increase is~~ primarily due to ~~$4 million in planned outage expenses offset by~~ a decrease of $23 million in the services agreement fee caused by a decrease in the allocation rate.

Income Tax Benefit. We reported an income tax benefit from continuing operations of $14 million and $18 million for the three months ended June 30, 2015 and June 30, 2014, respectively. The decrease in the benefit is primarily related to the decrease in our pretax loss when comparing the two periods.19

18Impairment and other charges. Increase in impairments is due to an impairment charge against the carrying value of our Coffeen generation facility during the three months ended September 30, 2015. Please read Note 4—Fair Value Measurements for further discussion.

~~Consolidated~~Income ~~Summary~~Tax ~~Financial~~Benefit. We ~~Information~~reported —a ~~Six~~$348 ~~Months~~million ~~Ended~~income ~~June~~tax benefit from continuing operations for the three months ended September 30, 2015, ~~Compared~~compared to ~~Six~~an ~~Months~~$11 ~~Ended~~million ~~June~~income tax benefit from continuing operations for the three months ended September 30, 2014. The increase in the benefit is primarily related to the increase in our pretax loss when comparing the two periods, mainly attributable to an impairment charge during the three months ended September 30, 2015.

~~The~~Consolidated ~~following~~Summary ~~table~~Financial ~~provides~~Information ~~summary~~— ~~financial~~Nine ~~data~~Months ~~regarding~~Ended ~~our~~September ~~consolidated~~30, ~~results~~2015 ofCompared ~~operations~~to ~~for~~Nine ~~the~~Months ~~six~~Ended ~~months~~September ~~ended June~~ 30, ~~2015 and~~ 2014, ~~respectively:~~

	Six Months Ended June 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2015			2014
Revenues	$	274		$	318		$	(44	)	(14	)%
Cost of sales, excluding depreciation expense	(177		)	(219		)	42			19	%
Gross margin	97			99			(2		)	(2	)%
Operating and maintenance expense	(88		)	(83		)	(5		)	(6	)%
Depreciation and amortization expense	(50		)	(48		)	(2		)	(4	)%
Operating loss	(41		)	(32		)	(9		)	(28	)%
Interest expense	(19		)	(20		)	1			5	%
Loss before income taxes	(60		)	(52		)	(8		)	(15	)%
Income tax benefit	25			21			4			(19	)%
Net loss	(35		)	(31		)	(4		)	(13	)%
Less: Net income (loss) attributable to noncontrolling interest	(3		)	2			(5		)	NM
Net loss attributable to Illinois Power Generating Company	$	(32	)	$	(33	)	$	1		(3	)%
Million Megawatt Hours Generated	7.7			9.3			(1.6		)	(17	)%
IMA for Genco Facilities (1)	93		%	90		%
Average Capacity Factor for Genco Facilities (2)	57		%	68		%
Average Power Prices ($/MWh) (3)	$	35.49		$	34.11		$	1.38		4	%

The following table provides summary financial data regarding our consolidated results of operations for the nine months ended September 30, 2015 and 2014, respectively:



	Nine Months Ended September 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
(amounts in millions)	2015			2014			Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Revenues	$	420		$	483		$	(63	)	(13	)%
Cost of sales, excluding depreciation expense	(265		)	(340		)	75			22	%
Gross margin	155			143			12			8	%
Operating and maintenance expense	(121		)	(120		)	(1		)	(1	)%
Impairment and other charges	(855		)	—			(855		)	(100	)%
Depreciation and amortization expense	(75		)	(73		)	(2		)	(3	)%
Operating loss	(896		)	(50		)	(846		)	NM
Interest expense	(29		)	(30		)	1			3	%
Loss before income taxes	(925		)	(80		)	(845		)	NM
Income tax benefit	373			32			341			NM
Net loss	(552		)	(48		)	(504		)	NM
Less: Net income (loss) attributable to noncontrolling interest	(1		)	2			(3		)	(150	)%
Net loss attributable to Illinois Power Generating Company	$	(551	)	$	(50	)	$	(501	)	NM

Million Megawatt Hours Generated	11.4			14.5			(3.1		)	(21	)%
IMA for Genco Facilities (1)	92		%	91		%
Average Capacity Factor for Genco Facilities (2)	55		%	71		%
Average Quoted Market Power Prices ($/MWh) (3)
On-Peak: Indiana (Indy Hub)	$	35.17		$	51.53		$	(16.36	)	(32	)%
Off-Peak: Indiana (Indy Hub)	$	25.41		$	33.68		$	(8.27	)	(25	)%

________________________________________


(1)	IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. This calculation excludes certain events outside of management control such as weather related issues.


(2)	Reflects actual production as a percentage of available capacity.

Discussion of Consolidated Results of Operations

Revenues. Revenues decreased by $4463 million from $~~318~~483 million for the ~~six~~nine months ended ~~June~~September 30, 2014 to $~~274~~420 million for the ~~six~~nine months ended ~~June~~September 30, 2015. The decrease is due to ~~$56 million in~~ lower energy revenues received through the PSAs as the result of ~~lower~~decreased ~~sales~~market ~~volumes~~prices primarily related to milder weather in 2015 and planned outages at our EEI and Newton facilities., ~~This decrease was~~ offset by anincreased ~~increase~~capacity ofrevenue ~~$12~~received ~~million~~through ~~due~~the toPSAs afrom higher ~~price~~capacity ~~per~~clearing ~~MWh~~prices ~~during~~for the ~~six~~nine months ended ~~June~~September 30, 2015. compared to the nine months ended September 30, 2014.

Cost of Sales. Cost of sales decreased by $42 million from $219 million for the six months ended June 30, 2014 to $177 million for the six months ended June 30, 2015. The decrease is primarily due to lower generation volumes during the six months ended June 30, 2015.

Operating and Maintenance Expense. Operating and maintenance expense increased by $5 million from $83 million for the six months ended June 30, 2014 to $88 million for the six months ended June 30, 2015. The increase is primarily due to a $3 million increase in accretion expense caused by an upward revision in ARO liability at the end of 2014 and a $4 million increase in planned outage expenses. The increases were offset by a $2 million decrease in the services agreement fee due to a lower allocation rate.

Income Tax Benefit. We reported an income tax benefit from continuing operations of $25 million and $21 million for the six months ended June 30, 2015 and June 30, 2014, respectively. The increase in the benefit is primarily related to the increase in our pretax loss when comparing the two periods.

Outlook

As of July 21, 2015, our expected remaining 2015 coal requirements are fully contracted and 95 percent priced. Our forecasted coal requirements for 2016 are 85 percent contracted and 66 percent priced. We look to procure and price additional fuel opportunistically. Our coal transportation requirements are fully contracted for 2015 and 2016. Our coal transportation requirements are approximately 77 percent contracted for 2017 to 2019. In addition, we recently entered into a new long-term transportation agreement for the Joppa facility. The new Joppa transport contract will begin in 2018 and is also a reduction from the 2017 rate.

Through IPM, we commercialize our assets through a combination of physical participation in the MISO markets and bilateral capacity sales. For Planning Year 2013-2014, Local Resource Zone 4 cleared at $1.05 per MW-day. For Planning Year 2014-2015, Local Resource Zone 4 cleared at $16.75 per MW-day. For Planning Year 2015-2016, Local Resource Zone 4 cleared at $150 per MW-day with 1,403 MW sold, including 996 MW that are expected to cover obligations which are realized through the PSAs, leaving 407 MW that will receive the $150 per MW-day clearing price. We expect asset retirements and confirmed future capacity exports from MISO to PJM to continue shrinking the supply of generation in the market. MISO has reversed its view that the reserve margin will fall below the needed generation level, known as the Planning Reserve Margin, which is currently 14.2 percent. MISO has forecasted reserve margins of 16.1 percent for Planning Year 2016-2017, 16.6 percent for Planning Year 2017-2018, 16.0 percent for Planning Year 2018-2019, 15.2 percent for Planning Year 2019-2020 and 14.7 percent for Planning Year 2020-2021.

In May of 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, Inc., 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. 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. Please read Note 8-Commitments and Contingencies-Contingencies-MISO 2015-2016 Planning Resource Auction Complaints for further information.

Midwest Electric Power, Inc. (“MEPI”), a wholly owned subsidiary of EEI, and Genco own simple cycle combustion turbines located at Joppa. MEPI owns two 35 MW units and Genco owns three 55 MW units (collectively the “Joppa CTs”). The Joppa CTs have been on maintenance outage since 2013. Three of the Joppa CTs were in service by the end of July 2015, and all maintenance work and testing necessary to bring the remaining two units back to operational status is expected to be completed in August 2015.

Through IPM, we also sell a portion of our capacity into the PJM control area. Capacity market prices within PJM are consistently higher than within MISO. In addition, PJM holds auctions several years in advance. In PJM, we cleared no volume in the Planning Year 2014-2015 capacity auction, 150 MW in the Planning Year 2015-2016 capacity auction, 425 MW in the Planning Year 2016-2017 capacity auction, and 416 MW in the Planning Year 2017-2018 capacity auction. The most recent PJM auction for Planning Year 2017-2018 cleared at $120 per MW-day. We have also secured one segment of the transmission path required to offer an additional 240 MW of capacity and energy into PJM.

PJM recently filed for FERC approval of changes to their capacity market with a product called Capacity Performance (“CP”). CP was developed by PJM in response to concerns about plant performance and system reliability. CP features increased availability and flexibility requirements, incentives for performance, significant penalties for non-performance and the ability to bid in a risk premium and recover costs previously disallowed by PJM and the independent market monitor.

On March 31, 2015, FERC issued a deficiency letter to PJM requesting additional information regarding certain elements of CP. PJM answered the deficiency letter on April 10, 2015. On April 24, 2015, FERC granted PJM’s request to delay the Planning Year 2018-2019 Base Residual Auction by up to 75 days (but no later than August 10, 2015) to give FERC time to rule on CP.

OnCost ~~June~~of ~~9, 2015, FERC conditionally approved PJM’s proposed CP product~~Sales. ~~Transitional~~Cost CPof ~~Auctions~~sales ~~will~~decreased beby ~~held~~$75 tomillion ~~procure~~from 60$340 ~~percent~~million CP for the ~~Planning~~nine ~~Year~~months ~~2016-2017~~ended ~~and~~September 7030, ~~percent~~2014 CPto $265 million for the ~~Planning~~nine ~~Year~~months ~~2017-2018. On~~ended ~~July~~September 2230, 2015,. The ~~FERC~~decrease ~~directed~~is ~~PJM~~primarily due to ~~include~~$75 ~~CP-eligible~~million ~~demand~~in ~~response~~lower ~~and~~coal ~~energy~~costs ~~efficiency~~due ~~products~~to ~~into~~planned ~~the~~outages ~~transitional~~and ~~auctions,~~decreased ~~which~~generation ~~will~~as ~~result in~~ a ~~delay~~result of ~~their~~milder ~~start~~weather ~~from~~during the ~~originally~~nine ~~scheduled~~months ~~dates. The~~ended ~~Base~~September ~~Residual Auction for the Planning Year 2018-2019 will be held August 10 - 14~~30, 2015.

WeOperating ~~recently~~and ~~reached~~Maintenance ~~agreement~~Expense. Operating onand ~~new~~maintenance ~~collective~~expense ~~bargaining~~increased ~~agreements~~by ~~with~~$1 million from $120 million for the ~~two~~nine ~~unions~~months ~~representing~~ended ~~our~~September ~~Coffeen~~30, ~~Newton~~2014 ~~and~~to ~~Joppa~~$121 ~~facilities. These~~million ~~agreements~~for ~~cover~~the ~~approximately~~nine ~~300~~months ~~represented~~ended ~~employees~~September ~~located~~30, 2015 primarily due to an increase in ~~Illinois~~accretion ~~and~~expense ~~expire~~caused ~~between~~by ~~2018~~an upward revision in ARO liability at the end of 2014 and ~~2020~~increased planned outage expenses of $5 million, offset by a decrease in the services agreement fee due to a lower allocation rate of the same amount.

Impairment and other charges. Increase in impairments is due to an impairment charge against the carrying value of our Coffeen generation facility during the nine months ended September 30, 2015. Please read Note 4—Fair Value Measurements for further discussion.

Income Tax Benefit. We reported an income tax benefit of $373 million and $32 million for the nine months ended September 30, 2015 and September 30, 2014, respectively. The increase in the benefit is primarily related to the increase in our pretax loss when comparing the two periods, mainly attributable to an impairment charge during the nine months ended September 30, 2015.

Outlook

As of October 19, 2015, our expected remaining 2015 coal requirements are fully contracted and 96 percent priced. Our forecasted coal requirements for 2016 are 84 percent contracted and 65 percent priced. We look to procure and price additional fuel opportunistically. Our coal transportation requirements are fully contracted for 2015 and 2016. Our coal transportation requirements are approximately 77 percent contracted for 2017 to 2019. In addition, we recently entered into a new long-term transportation agreement for the Joppa facility. The new Joppa transport contract will begin in 2018 and is also a reduction from the 2017 rate.

Through IPM, we commercialize our assets through a combination of physical participation in the MISO markets and bilateral capacity sales. For Planning Year 2013-2014, Local Resource Zone 4 cleared at $1.05 per MW-day. For Planning Year 2014-2015, Local Resource Zone 4 cleared at $16.75 per MW-day. For Planning Year 2015-2016, Local Resource Zone 4 cleared at $150 per MW-day with 1,403 MW sold, including 996 MW that are expected to cover obligations which are realized through the PSAs, leaving 407 MW that will receive the $150 per MW-day clearing price. We expect asset retirements and confirmed future capacity exports from MISO to PJM to continue shrinking the supply of generation in the market. MISO has a Planning Reserve Margin of 15.2 percent and has forecasted reserve margins of 16.1 percent for Planning Year 2016-2017, 16.6 percent for Planning Year 2017-2018, 16.0 percent for Planning Year 2018-2019, 15.2 percent for Planning Year 2019-2020 and 14.7 percent for Planning Year 2020-2021.

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, Inc., 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. 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.

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 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. Please read Note 8—Commitments and Contingencies-MISO 2015-2016 Planning Resource Auction for further information.

PJM has begun the transition of the PJM capacity market to its Capacity Performance (“CP”) product. On August 26-27, 2015, PJM held a transitional CP auction to convert up to 60 percent of PJM’s capacity needs for Planning Year 2016-2017 from legacy capacity to CP. On September 3-4, 2015, PJM held a transitional CP auction to convert 70 percent of PJM’s capacity needs for Planning Year 2017-2018 from legacy capacity to CP. On August 10-14, 2015, PJM held the BRA to procure CP for 80 percent and Base for 20 percent of PJM’s capacity needs for the Planning Year 2018-2019.

In the Planning Year 2016-2017 Transitional Auction, Genco converted its previously committed 425 MW of legacy capacity to 434 MW of CP. In the Planning Year 2017-2018 Transitional Auction, Genco converted 260 MW of its 416 MW legacy capacity to CP retaining 156 MW as legacy capacity. CP increased previous BRA prices from $59 per MW-day to $134 per MW-day for Planning Year 2016-2017; and $120 per MW-day to $152 per MW-day for Planning Year 2017-2018. CP for Planning Year 2018-2019 cleared $165 per MW-day. We have also secured one segment of the transmission path required to offer an additional 240 MW of capacity and energy into PJM.

Environmental and Regulatory Matters

Please read Item 1. Business-Environmental Matters in our Form 10-K and Item 2. Results of Operations-Outlook-Environmental and Regulatory Matters in our Form 10-Q for the period ended March 31, 2015 and June 30, 2015 for a detailed discussion of our environmental and regulatory matters.

The Clean Air Act

~~Mercury/HAPs~~National Ambient Air Quality Standards (“NAAQS”). On ~~June~~October 291, 2015, the ~~U.S.~~EPA ~~Supreme~~issued ~~Court~~a ~~found~~final ~~that~~rule lowering the ~~EPA~~primary ~~failed~~and tosecondary ~~properly~~NAAQS ~~consider~~for ~~costs~~ground-level ~~when~~ozone itfrom ~~promulgated~~75 ~~the~~to ~~MATS~~70 ~~rule~~parts per billion. ~~The~~In ~~Court~~accordance ~~remanded~~with the ~~cases~~CAA, to the ~~U.S.~~EPA ~~Court~~anticipates ofdesignating ~~Appeals~~attainment and nonattainment areas for the ~~District~~2015 ofozone ~~Columbia~~NAAQS ~~Circuit~~by October 1, 2017. State implementation plans for ~~further~~the ~~proceedings~~new ~~consistent~~ozone ~~with~~NAAQS ~~its~~generally ~~opinion~~would be due in 2020-2021. ~~The~~Based ~~MATS~~on ~~rule~~the ~~remains~~severity inof ~~effect~~nonattainment ~~pending~~designation, ~~further~~nonattainment ~~action~~areas bywould ~~the~~be ~~Court~~required ofto ~~Appeals~~achieve compliance between 2020 and 2037.

WeIn ~~believe~~August 2015, the ~~Supreme~~EPA ~~Court’s~~issued ~~decision~~a ~~will~~final ~~have~~rule ~~little~~regarding orthe no2010 ~~bearing~~one-hour onSO2 ~~the~~NAAQS ~~power~~that ~~markets,~~requires ~~given~~air agencies to characterize air quality around sources that ~~the~~emit ~~majority~~2,000 oftons ~~EGU~~per ~~retirement~~year ~~and~~or ~~investment~~more ~~decisions~~of ~~related~~SO2 tousing ~~MATS~~either ~~have~~ambient ~~already~~air ~~been~~quality ~~made~~measured at monitors or ~~are~~modeling ~~in-progress~~of source emissions. ~~Furthermore~~The rule requires air agencies to identify, ~~EGUs~~by ~~are~~July or2016, sources with SO2 emissions above 2,000 tons per year. For source areas that will be ~~subject~~evaluated through air quality modeling, the modeling analysis must be submitted to athe ~~number~~EPA ofby ~~other~~January ~~environmental~~2017. For ~~regulations~~source areas that ~~also~~will ~~affect~~be ~~retirement~~evaluated ~~and~~through ~~investment~~air ~~decisions~~quality monitoring, ~~such~~air asquality ~~the~~data ~~Coal~~will ~~Combustion~~be ~~Residuals~~collected ~~(“CCR”)~~for years 2017 through 2019. The rule will lead to the development of data that informs attainment and ~~Cross~~nonattainment area designations for the 2010 one-~~State~~hour ~~Air~~SO2 ~~Pollution~~NAAQS ~~Rule~~that ~~(“CSAPR”)~~are required by a court order to occur over the period July 2016 through December 2020. The EPA anticipates making final area designations for the majority of the country by December 2017, ~~and~~except for areas with new monitoring networks that begin operation in 2017 for which final designations would be made by December 2020. For areas designated nonattainment in 2017, the ~~anticipated~~EPA ~~Effluent~~anticipates ~~Limitation~~state ~~Guidelines~~implementation plans (~~“ELG”~~SIPs) ~~and~~would ~~Clean~~be ~~Power~~due ~~Plan~~in August 2019. For areas designated nonattainment in 2020, the EPA anticipates SIPs would be due in August 2022. Areas designated nonattainment must achieve attainment no later than five years after designation.

~~Given~~The nature and scope of potential future requirements concerning the ~~air~~2015 ozone NAAQS and 2010 one-hour SO2 NAAQS cannot be predicted with confidence at this time. A future requirement for additional emission ~~controls~~reductions ~~already~~of ~~employed,~~NOx weor ~~expect~~SO2 ~~that~~at ~~each~~any of our ~~facilities~~coal-fired ~~will~~generating befacilities infor ~~compliance~~purposes ~~with~~of the ~~MATS~~2010 ~~rule~~one-hour ~~emission~~SO2 ~~limits~~NAAQS ~~without~~or ~~the~~2014 ~~need~~ozone ~~for~~NAAQS ~~significant~~may ~~additional~~result ~~capital~~in ~~investment. We~~significantly ~~continue~~increased tocompliance ~~monitor~~costs ~~the~~and ~~performance~~could ofhave a material adverse effect on our ~~units~~financial ~~and~~condition, ~~evaluate~~results ~~approaches~~of tooperations ~~optimize~~and ~~compliance~~cash ~~strategies~~flows.

Cross-State Air Pollution Rule. On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit remanded without vacatur the CSAPR’s 2014 SO2 and ozone-season NOx emissions budgets for certain states to the EPA for reconsideration. The CSAPR emissions budgets for Illinois were not among those remanded. The court rejected all other challenges to the CSAPR.

National Ambient Air Quality Standards (“NAAQS”). In May 2015, the EPA issued a final rule that eliminates existing exemptions in the state implementation plans (“SIPs”) of many states, including Illinois, for emissions during periods of startup, shutdown or malfunction (“SSM”). Affected states are required to submit corrective SIP revisions to the EPA by November 22, 2016. While the EPA has determined, for example, that automatic exemptions of excess emissions during SSM periods do not meet CAA requirements, permissible SIPs may include alternative standards during SSM periods or include criteria and procedures for use of enforcement discretion by air agency personnel. Each state ultimately will have to decide how to address the specific SSM SIP inadequacies identified by the EPA.

The Clean Water Act

~~Waters~~Effluent ofLimitation ~~the~~Guidelines ~~United States~~(“ELG”). InOn ~~May~~September 30, 2015, the EPA ~~and~~issued a final rule revising the ~~U.S.~~ELG ~~Army~~for ~~Corps~~steam ofelectric ~~Engineers~~power ~~released~~generation aunits. The ELG final rule ~~defining~~establishes ~~the~~new ~~term~~or ~~“waters~~additional ofrequirements ~~the~~for ~~United~~wastewater ~~States~~streams associated with steam electric power generation processes and byproducts,” ~~which~~including isflue ~~used~~gas todesulfurization, ~~determine~~fly ~~the~~ash, ~~jurisdictional~~bottom ~~reach~~ash ofand ~~the~~flue ~~CWA~~gas mercury control. ~~Our~~For ~~facilities~~EGUs ~~may~~greater bethan ~~affected~~50 byMW, the final rule establishes a zero discharge standard for bottom ash transport water, fly ash transport water and flue gas mercury control wastewater. The ~~final~~ rule ~~identifies~~also ~~eight~~establishes ~~categories~~effluent oflimits ~~waters~~for ~~that~~flue ~~are~~gas ~~regulated~~desulfurization aswastewaters ~~“waters~~based ofon ~~the~~chemical ~~United~~precipitation ~~States,”~~and ~~including~~biological ~~waters~~treatment. Existing ~~that~~EGUs are ~~subject~~required to ~~case-specific~~comply ~~analysis~~with tothe ~~determine~~discharge ~~jurisdiction,~~limits ~~and~~in ~~also~~the ~~identifies~~ELG ~~categories~~final ofrule ~~waters~~by ~~that~~a ~~are~~date ~~excluded~~determined ~~from~~by ~~jurisdiction. Several~~the ~~states,~~permitting ~~business~~authority ~~groups~~that ~~and~~is ~~environmental~~as ~~organizations~~soon ~~have~~as ~~filed~~possible ~~lawsuits~~beginning ~~challenging~~November ~~the~~1, ~~final~~2018, ~~rule~~but no later than December 31, 2023.

We are currently evaluating the ELG final rule and the CCR rule to determine whether current management of CCR, including beneficial reuse, and the use of the CCR surface impoundments should be altered. We are also evaluating the potential costs to comply with these regulations, which could be material. The ELG final rule’s zero discharge standard on bottom ash transport water on all units greater than 50 MW may add material compliance costs to our preliminary cost estimate of approximately

$46 million for compliance with the ELG rule, which we are currently reviewing. The majority of ELG compliance spend is expected to occur in the 2018-2023 timeframe. Our estimate and timing could change significantly depending upon a variety of factors, including detailed site-specific engineering analyses, the outcome of potential litigation concerning the ELG final rule, and our final compliance plans with the EPA’s CCR rule.

Waters of the United States. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying the EPA and the U.S. Army Corps of Engineers’ final rule defining the term “waters of the United States” pending further review by the court.

Coal Combustion Residuals

~~EPA CCR Rule~~Illinois. In ~~July~~October ~~2015~~2013, ~~several~~the ~~businesses~~Illinois EPA filed a proposed rulemaking with the IPCB that would establish processes governing monitoring, ~~industry~~corrective ~~groups~~action and ~~environmental~~closure ~~organizations~~of ~~filed~~CCR ~~petitions~~surface ~~for~~impoundments ~~judicial~~at ~~review~~power generating facilities. The Illinois EPA’s proposed rulemaking has been stayed since May 2015 to consider the implications of the federal EPA’s ~~final~~ CCR rule. In November 2015, the IPCB extended the stay until early March 2016, at which time the Illinois EPA is required to provide a status report.

Illinois. In October 2013, the Illinois EPA filed a proposed rulemaking with the IPCB that would establish processes governing monitoring, corrective action and closure of CCR surface impoundments at power generating facilities. In May 2015, the IPCB granted the Illinois EPA’s request for a 90-day stay of the rulemaking proceeding to consider the implications of the EPA final CCR rule. In August 2015, the Illinois EPA requested that the IPCB stay the rulemaking proceeding indefinitely to enable the Agency and interested parties to evaluate the impact of legal and legislative actions concerning the EPA final CCR rule.

Climate Change

Federal Regulation of Greenhouse Gases. OnNumerous ~~August 3~~states, ~~2015~~industry associations, ~~the~~labor ~~EPA~~groups ~~released~~and asothers ahave ~~final~~filed ~~rule~~lawsuits challenging the ~~Clean Power Plan to reduce carbon emissions from existing EGUs. The~~ EPA’s ~~also issued its~~ final ~~rules regarding carbon standards for new, modified and reconstructed EGUs, and a proposed federal plan and model~~ rule ~~to assist states in implementing the~~ Clean Power Plan. ~~The~~ Numerous ~~Clean~~parties ~~Power~~challenging ~~Plan,~~the ~~when~~rule ~~fully~~also ~~implemented~~filed inmotions ~~2030,~~to ~~would~~stay ~~reduce~~the ~~CO2~~rule ~~emissions~~pending ~~from~~completion ~~EGUs~~of byjudicial ~~32 percent from 2005 levels~~review. ~~States~~ In ~~would~~addition, benumerous ~~required~~states toand ~~develop~~others ~~plans~~have tofiled ~~achieve~~lawsuits ~~interim~~challenging ~~CO2 emission rates reductions phased in over~~ the ~~period~~EPA’s ~~2022~~final torule ~~2029~~regarding ~~and~~carbon ~~the~~standards ~~final CO2 rate~~ for ~~their state by 2030. States must submit final plans by September 6~~new, ~~2016,~~modified ~~unless~~and areconstructed ~~state makes certain demonstrations justifying a two-year extension for submittal of a final plan by September 2018~~EGUs.

InWe ~~June~~are ~~2015~~analyzing the EPA’s final rules to reduce EGU carbon dioxide (“CO2”) emissions, the ~~U.S.~~potential ~~Court~~impacts ofon ~~Appeals~~our ~~for~~power generation facilities, and how the ~~District~~rules intersect with electricity market design. The nature and scope of ~~Columbia~~CO2 ~~Circuit~~emission ~~dismissed~~reduction ~~petitions~~requirements ~~challenging~~that ultimately may be imposed on our facilities as result of the EPA’s ~~proposed~~EGU ~~Clean~~CO2 ~~Power~~reduction ~~Plan~~rules onare ~~the~~uncertain ~~grounds~~at ~~that~~this ~~the~~time, ~~rule~~but ~~was~~may ~~not~~result ~~yet~~in ~~final. Petitions~~significantly ~~for~~increased ~~rehearing~~compliance costs and could have ~~been~~a ~~filed. Legal~~material ~~challenges~~adverse toeffect ~~the~~on ~~final~~our ~~rule~~financial ~~Clean~~condition, ~~Power~~results ~~Plan~~of ~~are~~operations ~~expected~~and cash flows.

We are analyzing the EPA’s final rules to reduce EGU CO2 emissions, the potential impacts on our power generation facilities, and how the rules intersect with electricity market design. The nature and scope of CO2 emission reduction requirements that ultimately may be imposed on our facilities as result of the EPA’s EGU CO2 reduction rules are uncertain at this time, but may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements.” All statements included or incorporated by reference in this quarterly report, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment of the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “project,” “forecast,” “plan,” “may,” “will,” “should,” “expect” and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:


•	beliefs and assumptions about weather and general economic conditions;

• beliefs, assumptions and projections regarding the demand for power, generation volumes and commodity pricing, including natural gas prices and the timing of a recovery in ~~natural~~power ~~gas~~market prices, if any;


•	beliefs and assumptions about market competition, generation capacity and regional supply and demand characteristics of the wholesale and retail power markets, including the anticipation of plant retirements and higher market pricing over the longer term;


•	sufficiency of, access to and costs associated with coal inventories and transportation thereof;


•	the effects of, or changes to, MISO or PJM power and capacity procurement processes;

• ~~expectations~~beliefs ~~regarding~~associated ~~environmental~~with ~~matters,~~impairments ~~including costs~~ of ~~compliance,~~our ~~availability~~long-lived and adequacy of emission credits and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion residuals, wastewater discharges, and other laws and regulations to which we are, or could become, subjectassets;

•

expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise have a negative financial effect;


•	projected operating or financial results, including anticipated cash flows from operations, revenues and profitability;


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


•	our assessment of our liquidity, including liquidity concerns which have resulted in limited access to third-party financing sources;


•	expectations regarding our compliance with the unsecured notes indenture and any applicable financial ratios and other payments;


•	beliefs about the outcome of legal, administrative, legislative and regulatory matters;


•	our focus on safety and our ability to efficiently operate our assets so as to capture revenue generating opportunities and operating margins;

• our ability to mitigate forced outage risk, asincluding wemanaging ~~become~~risk ~~subject~~associated towith ~~proposed~~CP ~~capacity performance~~ in PJM;


•	our ability to optimize our assets through targeted investment in cost effective technology enhancements;


•	the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility;


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


•	efforts to identify opportunities to reduce congestion and improve busbar power prices;


•	expectations regarding performance standards and capital and maintenance expenditures; and


•	the timing and anticipated benefits to be achieved through our company-wide improvement programs, including our Producing Results through Innovation by Dynegy Employees (“PRIDE”) initiative.

Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond our control, including those set forth under Part I—Item 1A—Risk Factors of our Form 10-K.

CRITICAL ACCOUNTING POLICIES

Please read “Critical Accounting Policies” in our Form 10-K for a complete description of our critical accounting policies, with respect to which there have been no material changes since the filing of such Form 10-K.

Item 3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Please read Part II—Item 7A—Quantitative and Qualitative Disclosures about Market Risk in our Form 10-K for the year ended December 31, 2014 for detailed disclosures about market risk. There have been no changes in our market risk exposures and how those exposures are managed during the ~~six~~nine months ended ~~June~~September 30, 2015.

Item 4—CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”) and our Chief Financial Officer (“CFO”), of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended). This evaluation included consideration of the various processes carried out under the direction of our disclosure committee. This evaluation also considered the work completed relating to our compliance with Section 404 of the Sarbanes-Oxley Act of 2002. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of ~~June~~September 30, 2015.

Changes in Internal Controls Over Financial Reporting

There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the quarter ended ~~June~~September 30, 2015.

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PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS

Please read Note 8—Commitments and Contingencies to the accompanying unaudited consolidated financial statements for a discussion of the legal proceedings that we believe could be material to us.

Item 1A—RISK FACTORS

Please read Item 1A— - Risk Factors, of our Form 10-K and below for factors, risks and uncertainties that may affect future results.

We could recognize additional long-lived asset impairment charges related to our facilities.

We continuously monitor the market price for power and the related impact on electric margin, our liquidity needs, and other events or changes in circumstances that indicate that the carrying value of our facilities may not be recoverable as compared to their undiscounted cash flows. We could recognize material long-lived asset impairment charges in the future if estimated undiscounted future cash flows no longer exceed carrying values for long-lived assets. This may occur either as a result of factors outside our control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of our facilities, and also as a result of factors that may be within our control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell our facilities.

Item 6—EXHIBITS

The following documents are included as exhibits to this Form 10-Q:

Exhibit Number		Description
**10.1		Second Amendment dated June 29, 2015, to Amended and Restated Power Sales Agreement dated July 31, 2009, between Illinois Power Marketing Company and Electric Energy, Inc.
**31.1		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**31.2		Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
†32.1		Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†32.2		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**101.INS		XBRL Instance Document
**101.SCH		XBRL Taxonomy Extension Schema Document
**101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF		XBRL Taxonomy Extension Definition Document
**101.LAB		XBRL Taxonomy Extension Label Linkbase Document
**101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

_________________________________________

** Filed herewith.

† Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act.

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

			ILLINOIS POWER GENERATING COMPANY
Date:	~~August~~November 1110, 2015	By:	/s/ CLINT C. FREELAND
			Clint C. FreelandExecutive Vice President and Chief Financial Officer (Principal Financial Officer)

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