Illinois Power Generating Co - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - Illinois Power Generating Co	Financial_Report.xls
EX-31.2 - CHIEF FINANCIAL OFFICER 302 CERTIFICATION - Illinois Power Generating Co	genco2014063010qex312.htm
EX-32.2 - CHIEF FINANCIAL OFFICER 906 CERTIFICATION - Illinois Power Generating Co	genco2014063010qex322.htm
EX-31.1 - CHIEF EXECUTIVE OFFICER 302 CERTIFICATION - Illinois Power Generating Co	genco201463010qex311.htm
EX-32.1 - CHIEF EXECUTIVE OFFICER 906 CERTIFICATION - Illinois Power Generating Co	genco2014063010qex321.htm

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 30, 2014

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 1, 2014, 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
PART I Financial Information

Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	1
	Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013	2
	Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2014 and 2013	3
	Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013	4
	Notes to Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	20
Item 4.	Controls and Procedures	20

PART II Other Information

Item 1.	Legal Proceedings	21
Item 1A.	Risk Factors	21
Item 6.	Exhibits	21

Signature		22

GLOSSARY OF TERMS AND ABBREVIATIONS

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



AER		Ameren Energy Resources, LLC
Ameren		Ameren Corporation
Ameren Services		Ameren Services Company
AOCI		Accumulated Other Comprehensive Income
ARO		Asset Retirement Obligation
ASU		Accounting Standards Update
BACT		Best Available Control Technology
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CCR		Coal Combustion Residuals
CEO		Chief Executive Officer
CFO		Chief Financial Officer
CO₂		Carbon Dioxide
CSAPR		Cross-State Air Pollution Rule
CT		Combustion turbine
DOE		Department of Energy
Dynegy		Dynegy Inc.
EEI		Electric Energy, Inc.
EGU		Electric Utility Steam Generating Units
EPA		Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
GAAP		Generally Accepted Accounting Principles of the United States of America
GHG		Greenhouse Gas
HAPs		Hazardous Air Pollutants, as defined by the Clean Air Act
IASB		International Accounting Standards Board
IFRS		International Financial Reporting Standards
IGCC		Integrated Gasification Combined Cycle
IPCB		Illinois Pollution Control Board
IPGC or Genco		Illinois Power Generating Company (formerly known as Ameren Energy Generating Company)
IPH		Illinois Power Holdings, LLC
IPM		Illinois Power Marketing Company (formerly known as Ameren Energy Marketing Company)
IPR		Illinois Power Resources, LLC (formerly known as New Ameren Energy Resources, LLC)
IPRG		Illinois Power Resources Generating LLC (formerly known as New AERG, LLC)
MISO		Midcontinent Independent System Operator, Inc.
MMBtu		One Million British Thermal Units
Moody’s		Moody’s Investors Service Inc.
MPS		Multi-Pollutant Standards
MW		Megawatts
MWh		Megawatt Hour
New AER		New Ameren Energy Resources, LLC
NOL		Net operating loss
NO_x		Nitrogen Oxide
NPDES		National Pollutant Discharge Elimination System
NSPS		New Source Performance Standards
NSR		New Source Review
PJM		PJM Interconnection, LLC



PSA		Power Supply Agreement
PSD		Prevention of Significant Deterioration
S&P		Standard & Poor’s Ratings Services
SEC		U.S. Securities and Exchange Commission
SO2		Sulfur Dioxide

PART I. FINANCIAL INFORMATION

ILLINOIS POWER GENERATING COMPANY CONSOLIDATED BALANCE SHEETS (unaudited) (in millions, except share data)

	June 30, 2014			December 31, 2013
ASSETS
Current Assets
Cash and cash equivalents	$	182		$	190
Accounts receivable, affiliates	53			59
Accounts receivable	12			18
Inventory	81			78
Prepayments and other current assets	11			18
Total Current Assets	339			363
Property, Plant and Equipment	2,930			2,900
Accumulated depreciation	(1,075		)	(1,027		)
Property, Plant and Equipment, Net	1,855			1,873
Other Assets	33			28
Total Assets	$	2,227		$	2,264
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable	$	37		$	38
Accounts payable, affiliates	12			—
Taxes accrued	17			12
Accrued interest	10			10
Current accumulated deferred income taxes, net	18			19
Accrued liabilities and other current liabilities	15			15
Total Current Liabilities	109			94
Long-term debt	824			824
Other Liabilities
Accumulated deferred income taxes, net	492			520
Asset retirement obligations	45			43
Other long-term liabilities	25			20
Total Liabilities	1,495			1,501
Commitments and Contingencies (Note 9)

Stockholder’s Equity
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding	—			—
Additional paid-in capital	551			551
Retained earnings	183			216
Accumulated other comprehensive loss, net of tax	(11		)	(11		)
Total Illinois Power Generating Company Stockholder’s Equity	723			756
Noncontrolling interest	9			7
Total Equity	732			763
Total Liabilities and Equity	$	2,227		$	2,264

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,
	2014			2013			2014			2013
Revenues	$	138		$	181		$	318		$	375
Cost of sales, excluding depreciation expense	(105		)	(139		)	(219		)	(270		)
Gross margin	33			42			99			105
Operating and maintenance expense	(44		)	(54		)	(83		)	(90		)
Impairment and other charges	—			5			—			(202		)
Depreciation and amortization	(24		)	(18		)	(48		)	(42		)
Operating loss	(35		)	(25		)	(32		)	(229		)
Interest expense	(10		)	(10		)	(20		)	(21		)
Loss before income taxes	(45		)	(35		)	(52		)	(250		)
Income tax benefit	18			13			21			99
Net loss	(27		)	(22		)	(31		)	(151		)
Less: Net income attributable to noncontrolling interest	—			—			2			—
Net loss attributable to Illinois Power Generating Company	$	(27	)	$	(22	)	$	(33	)	$	(151	)

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,
	2014			2013			2014			2013
Net loss	$	(27	)	$	(22	)	$	(31	)	$	(151	)
Other comprehensive loss before reclassifications:
Actuarial loss due to pension plan remeasurement (net of tax benefit of zero, zero, $1 million and zero, respectively)	—			—			(2		)	—
Amounts reclassified from accumulated other comprehensive loss:
Settlement loss on pension plan (net of tax benefit of zero, zero, zero and zero, respectively)	1			—			2			—
Amortization of unrecognized prior service cost and actuarial gain (net of tax benefit of zero, $1 million, zero and $1 million, respectively)	—			1			—			2
Other comprehensive income, net of tax	1			1			—			2
Comprehensive loss	(26		)	(21		)	(31		)	(149		)
Less: Comprehensive income attributable to noncontrolling interest	—			—			2			—
Total comprehensive loss attributable to Illinois Power Generating Company	$	(26	)	$	(21	)	$	(33	)	$	(149	)

See the notes to consolidated financial statements.

ILLINOIS POWER GENERATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (in millions)

	Six Months Ended June 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(31	)	$	(151	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Loss on asset impairment	—			202
Depreciation expense	48			42
Risk management activities	—			(2		)
Gain on sale of assets, net	—			(1		)
Deferred income taxes and investment tax credits, net	(28		)	(68		)
Other	2			1
Changes in working capital:
Accounts receivable, net	4			12
Inventory	1			20
Prepayments and other current assets	7			—
Accounts payable and accrued liabilities	15			5
Other	—			(6		)
Net cash provided by operating activities	18			54
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(26		)	(29		)
Proceeds from asset sales, net	—			100
Money pool advances, net	—			(125		)
Net cash used in investing activities	(26		)	(54		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net cash provided by financing activities	—			—
Net decrease in cash and cash equivalents	(8		)	—
Cash and cash equivalents, beginning of year	190			25
Cash and cash equivalents, end of period	$	182		$	25

See the notes to consolidated financial statements.

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2014 and 2013

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 SEC. The year-end consolidated balance sheet data was derived from audited consolidated financial statements but does not include all disclosures required by 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, 2013, filed with the SEC on March 28, 2014, 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.

On December 2, 2013 (the “Acquisition Date”), we were acquired indirectly by Illinois Power Holdings, LLC (“IPH”), an indirect wholly-owned subsidiary of Dynegy. On the Acquisition Date, pursuant to the terms of the definitive agreement dated as of March 14, 2013 and as amended on the Acquisition Date (the “AER Transaction Agreement”) by and between IPH and Ameren Corporation (“Ameren”), IPH completed its acquisition from Ameren of 100 percent of the equity interests of New Ameren Energy Resources, LLC (“New AER”) and its subsidiaries (the “AER Acquisition”). “Push-down accounting” was not applied as a result of the AER Acquisition, which would require the adjustment of the assets and liabilities to fair value recognized by Dynegy to be shown in our consolidated financial statements. IPH and its direct and indirect subsidiaries, including Genco, are organized into ring-fenced groups to maintain corporate separateness from Dynegy and its other subsidiaries, for the purpose of minimizing risk of claims against Dynegy for IPH’s and our obligations. We have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. We maintain separate books, records and bank accounts and separately appoint officers. Furthermore, we pay liabilities from our own funds, conduct business in our own name and have restrictions on pledging our assets for the benefit of certain other persons.

Reclassifications

Certain prior period amounts in our consolidated statements of operations have been reclassified to conform to current year presentation.

Note 2—Accounting Policies

The accounting policies followed by the Company are set forth in Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Form 10-K. There have been no significant changes to these policies during the six months ended June 30, 2014.

The preparation of consolidated financial statements in conformity with GAAP requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. Actual results could differ materially from our estimates. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures and other factors.

Accounting Standards Adopted During the Current Period

Presentation of Unrecognized Tax Benefits. In July 2013, the FASB issued ASU 2013-11-Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The provisions of the rule require an unrecognized tax benefit to be presented as a reduction to a deferred tax asset in the financial statements for an NOL carryforward, a similar tax loss, or a tax credit carryforward except in circumstances when the carryforward or tax loss is not available at the reporting date under the tax laws of the applicable jurisdiction to settle any additional income taxes or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes. When those circumstances exist, the unrecognized tax benefit should be presented in the financial statements

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2014 and 2013

as a liability and should not be combined with deferred tax assets. The new financial statement presentation provisions relating to this ASU are prospective and effective for interim and annual periods beginning after December 15, 2013. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Accounting Standards Not Yet Adopted

Reporting Discontinued Operations and Asset Disposals. In April 2014, the FASB issued ASU 2014-08-Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosure of Disposals of Components of an Entity. The amendments in this ASU change the requirements for reporting discontinued operations in Subtopic 205-20. An entity is required to report within discontinued operations on the statement of operations the results of a component or group of components of an entity if the disposal represents a strategic shift that has, or will have, a major effect on an entity’s operations and financial results. Additionally, the associated assets and liabilities are required to be presented separately from other assets and liabilities on the balance sheet for all comparative periods. The ASU includes updated guidance regarding what meets the definition of a component of an entity. The new financial statement presentation provisions relating to this ASU are prospective and effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. We do not anticipate the adoption of this ASU having a material impact on our consolidated financial statements.

Revenue from Contracts with Customers. In May 2014, the FASB and 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 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, 2016. We are currently assessing this ASU; however, we do not anticipate a material impact on our consolidated financial statements.

Note 3—Asset Sales

In October 2013, we divested our Elgin, Gibson City and Grand Tower gas-fired facilities (the “Gas-Fired Facilities”) to Ameren Energy Medina Valley Cogen L.L.C. (“Medina Valley”), an affiliate of Ameren Energy Resources Company, LLC (“AER”) that IPH did not acquire in the AER Acquisition, under a put option agreement that was assumed by Medina Valley and exercised by us in March 2013 (the “Put Option”). As a result of our exercise of the Put Option, the Gas-Fired Facilities qualified for held for sale accounting and we recorded a pretax charge to earnings of $207 million during the three months ended March 31, 2013 to reflect the impairment of the Gas-Fired Facilities as the carrying value of the facilities exceeded their fair value. Fair value was based on the purchase agreement with Medina Valley. The impairment charge decreased by $5 million during the three months ended June 30, 2013, as the carrying value of the Gas-Fired Facilities decreased primarily as a result of derivative market value losses, resulting in a pretax charge to earnings of $202 million during the six months ended June 30, 2013 to reflect the impairment of the Gas-Fired Facilities.

Note 4—Risk Management, Derivatives and Financial Instruments

Derivatives on the Balance Sheet. We did not have a material amount of derivative instruments as of June 30, 2014 and December 31, 2013.

Impact of Derivatives on the Consolidated Statements of Operations

The cumulative amount of pretax net losses on interest rate derivative instruments in AOCI was $6 million as of June 30, 2014 and December 31, 2013. 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 over a 10-year period that began in April 2008, $1.4 million of which will be amortized through 2014.

Financial Instruments Not Designated as Hedges. In 2014 and 2013, we elected not to designate derivatives related to our power generation business and interest rate instruments as cash flow or fair value hedges. Thus, we account for changes in the fair value of these derivatives within the consolidated statements of operations (herein referred to as “mark-to-market” accounting treatment).

There was no material impact of mark-to-market gains (losses) on our unaudited consolidated statements of operations for the three and six months ended June 30, 2014. Revenues on our unaudited consolidated statements of operations for the three

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2014 and 2013

and six months ended June 30, 2013 include mark-to-market losses of $4 million and mark-to-market gains of $2 million, respectively, related to our commodity derivatives.

Note 5—Fair Value Measurements

We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, our valuation techniques maximize the use of observable inputs and minimize the use of unobservable inputs. We have consistently used this valuation technique for all periods presented. Please read Note 9—Fair Value Measurements in our Form 10-K for further discussion and definitions of the fair value hierarchy.

We did not have material amounts of outstanding derivative positions as of June 30, 2014 and December 31, 2013.

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.

The carrying values of financial assets and liabilities (cash and cash equivalents, 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, 2014 and December 31, 2013, respectively. All fair values presented below are classified within Level 2 of the fair value hierarchy.



	June 30, 2014				December 31, 2013
(amounts in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
7.95% Senior Notes Series F, due 2032 (1)	$	274	$	279	$	274	$	216
7.00% Senior Notes Series H, due 2018	$	300	$	300	$	300	$	252
6.30% Senior Notes Series I, due 2020	$	250	$	246	$	250	$	196

__________________________________________


(1)	Carrying amount includes unamortized discount of $1 million as of June 30, 2014 and December 31, 2013. Please read Note 8—Debt for further discussion.

Note 6—Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss), net of tax, by component, associated with our defined benefit pension and other post-employment benefit plans are as follows:



	Six Months Ended June 30,
(amounts in millions)	2014			2013
Beginning of period	$	(11	)	$	(40	)
Current period other comprehensive loss:
Actuarial loss due to pension plan remeasurement (net of tax benefit of $1 million and zero, respectively)	(2		)	—
Amounts reclassified from accumulated other comprehensive loss:
Settlement loss on pension plan (net of tax benefit of zero and zero, respectively) (1)	2			—
Amortization of unrecognized prior service cost and actuarial gain (net of tax benefit of zero and zero, respectively) (2)	—			2
Net current period other comprehensive income, net of tax	—			2
End of period	$	(11	)	$	(38	)

_______________________________________


(1)	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 12—Pension and Other Post-Employment Benefits for further discussion.

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2014 and 2013


(2)	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 12—Pension and Other Post-Employment Benefits for further discussion.

Note 7—Inventory

A summary of our inventories is as follows:



(amounts in millions)	June 30, 2014		December 31, 2013
Materials and supplies	$	30	$	33
Coal	49		43
Fuel oil	2		2
Total	$	81	$	78

Note 8—Debt

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



(amounts in millions)	June 30, 2014			December 31, 2013
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

At June 30, 2014, we were in compliance with the provisions and covenants contained within our indenture. Our indenture includes provisions that require us to maintain certain interest coverage and debt-to-capital ratios in order for us to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these required ratios as of June 30, 2014:



		Required Ratio
Interest coverage ratio- restricted payment (1)		≥1.75
Interest coverage ratio- additional indebtedness (2)		≥2.50
Debt-to-capital ratio- additional indebtedness (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 30, 2014 calculations, our interest coverage ratios are less than the minimum ratios required to pay dividends and borrow additional funds from external, third-party sources. Based on projections of operating results and cash flows in 2014 and 2015 as of June 30, 2014, we do not believe that we will achieve the minimum

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2014 and 2013

interest coverage ratio necessary to pay dividends on our common stock and incur additional third-party indebtedness until at least 2016. As a result, we were restricted from paying dividends as of June 30, 2014.

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 9—Commitments and Contingencies

Legal Proceedings

Set forth below is a summary of our material ongoing legal proceedings. We record accruals for estimated losses from contingencies when available information indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, we disclose matters for which management believes a material loss is reasonably possible. In all instances, management has assessed the matters below based on current information and made judgments concerning their potential outcome, giving consideration to the nature of the claim, the amount, if any, and nature of damages sought and the probability of success. Management regularly reviews all new information with respect to such contingency 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 our legal proceedings could involve amounts that are different from our currently recorded accruals and that such differences could be material.

In addition to the matters discussed below, we are party to other routine proceedings arising in the ordinary course of business or related to discontinued business operations. 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.

Variance. In January 2014, an environmental group filed a petition for review in the Illinois Fourth District Appellate Court of the IPCB’s November 2013 decision and order granting IPH a variance extending the applicable compliance dates for MPS SO₂emission limits. On January 17, 2014, IPH filed a Motion to Dismiss. On February 24, 2014, the Fourth District Appellate Court granted the motion and dismissed the appeal. On April 1, 2014, the environmental group filed a petition for leave to appeal the Appellate Court’s decision with the Illinois Supreme Court. On May 5, 2014, we filed an answer opposing review by the Illinois Supreme Court. We believe the variance was properly granted and that the Appellate Court’s judgment dismissing the petition for review was proper. We will vigorously defend our position.

New Source Review and Clean Air Litigation

Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the CAA when the plants implemented modifications. The EPA’s initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment.

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 Coffeen, Newton and Joppa facilities. In August 2012, we received a Notice of Violation from the EPA alleging violations of permitting requirements at our Newton facility, including Title V of the CAA. The EPA contends that projects performed in 1997, 2006 and 2007 at our Newton facility violated federal law. We believe our defenses to the allegations described in the Notice of Violation are meritorious. A recent decision by the United States Court of Appeals for the Seventh Circuit held that similar claims older than five years were barred by the statute of limitations. If not overturned, this decision may provide an additional defense to the allegations in the Newton facility Notice of Violation. Ultimate resolution of these matters could have a material adverse impact on our future financial condition, results of operations and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve these matters.

Groundwater

Hydrogeologic investigations of the CCR surface impoundments have been performed at our facilities. Groundwater monitoring results indicate that the CCR surface impoundments at each of our facilities potentially impact onsite groundwater.

The Illinois EPA has issued violation notices with respect to groundwater conditions at our Coffeen and Newton 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 April 2013, AER filed a proposed

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2014 and 2013

rulemaking with the IPCB which, if approved, would provide for the systematic and eventual closure of our CCR surface impoundments. In October 2013, the Illinois EPA filed a proposed rulemaking with the IPCB that would establish processes governing monitoring, preventative response, corrective action and closure of CCR surface impoundments at all power generating facilities in Illinois. The AER rulemaking has been stayed to allow the Illinois EPA proposed rulemaking to proceed. At this time we cannot reasonably estimate the costs or range of costs of resolving the Newton and Coffeen enforcement matters, but resolution of these matters may cause us to incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. During the first quarter 2013, we revised our ARO fair value estimates relating to CCR surface impoundments.

Guaranty Agreement

In connection with the AER Acquisition, Genco has provided a Guaranty Agreement of certain obligations of IPH under the AER Transaction Agreement. Concurrently with the closing of the AER Transaction Agreement on the Acquisition Date, Genco entered into the Guaranty Agreement in favor of Ameren, pursuant to which Genco guaranteed certain of IPH’s credit support obligations and tax and environmental indemnification obligations under the AER Transaction Agreement.

Note 10—Related Party Transactions

We have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of power purchases and sales, services received or rendered, and borrowings and lendings. For a discussion of our material related party agreements, please read Note 2—Related Party Transactions of the Form 10-K.

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



	June 30, 2014				December 31, 2013
(amounts in millions)	Accounts Receivable, Affiliates		Accounts Payable, Affiliates		Accounts Receivable, Affiliates		Accounts Payable, Affiliates
Power supply agreements	$	51	$	—	$	58	$	—
Services agreement	1		—		—		—
Tax sharing agreement	—		8		—		—
Other	1		4		1		—
Total	$	53	$	12	$	59	$	—

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, 2014 and 2013. It is based primarily on the agreements discussed below and in Note 2—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	2014		2013		2014		2013
Power supply agreements	Revenues	$	137	$	153	$	317	$	338
Services provided to AER affiliates	Revenues	$	—	$	2	$	—	$	4
Services agreement	Operating and maintenance expense	$	11	$	3	$	21	$	6
EEI power supply agreement	Cost of sales	$	—	$	18	$	—	$	18

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2014 and 2013

Power Supply Agreements

Genco has a PSA with Illinois Power Marketing Company (“IPM”), 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, revenues allocated between Genco and IPRG are based on reimbursable expenses and generation of each entity. Each PSA will continue through December 31, 2022, and from year to year thereafter. Either party to the respective PSA may elect to terminate the PSA by providing the other party with no less than six months advance written notice.

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

Collateral Agreement

On February 26, 2014, Genco entered into 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

Prior to the AER Acquisition, Ameren Services Company (“Ameren Services”), an Ameren subsidiary, provided support services to its affiliates, including us. The costs of services, including wages, employee benefits, professional services, and other expenses, were based on, or were an allocation of, actual costs incurred. In addition, we provided affiliates, primarily Ameren Services, with access to our facilities for administrative purposes. The cost of the rent and facility services were based on, or were an allocation of, actual costs incurred.

Upon the AER Acquisition, Dynegy and certain of its subsidiaries (collectively, the “Providers”) began providing certain services (the “Services”) to IPH, and certain of its consolidated subsidiaries (collectively, the “Recipients”), which includes us and EEI.

The Providers act as agents for the Recipients for the limited purpose of providing the Services set forth in the service agreements. Prior to the beginning of each fiscal year in which Services are to be provided pursuant to the Service Agreements, the Providers and the Recipients agree on a budget for the Services, outlining, among other items, the contemplated scope of the Services to be provided in the following fiscal year and the cost of providing the Services. The Recipients will pay the Providers an annual management fee as agreed in the budget. We believe this 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.

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 have entered into a tax sharing agreement that also provides that we recognize taxes based on a separate company income tax return basis, as defined in the agreement.

Note 11—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 for significant unusual or extraordinary transactions. Income taxes for significant unusual or extraordinary transactions are computed and recorded in the period that the specific transaction occurs.

For the three months ended June 30, 2014, our overall effective tax rate on continuing operations of 40 percent was different than the statutory tax rate of 35 percent primarily due to the impact of state income tax.

For the six months ended June 30, 2014, our overall effective tax rate on continuing operations of 40 percent was different than the statutory tax rate of 35 percent primarily due to the impact of state income tax.

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2014 and 2013

Note 12—Pension and Other Post-Employment Benefits

We offer defined benefit pension and 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 post-employment balances and disclosures. Please read Note 6—Retirement Benefits in our Form 10-K for further discussion.

Components of Net Periodic Benefit Cost. The following table presents the components of our net periodic benefit cost of the EEI pension and post-employment benefit plans for the three and six months ended June 30, 2014 and 2013. Also reflected is an allocation of net periodic benefit costs from our participation in Dynegy’s single-employer pension and post-employment plans for the three and six months ended June 30, 2014 and Ameren’s single-employer pension and post-employment plans for the three and six months ended June 30, 2013.



	Pension Benefits						Post-employment Benefits
	Three Months Ended June 30,
(amounts in millions)	2014			2013			2014			2013
Service cost	$	—		$	1		$	—		$	—
Interest cost	1			3			—			1
Expected return on plan assets	(1		)	(4		)	(1		)	(1		)
Amortization of:
Prior service cost	—			—			(1		)	(2		)
Actuarial gain	—			2			1			1
Net periodic benefit cost (gain)	—			2			(1		)	(1		)
Settlements	1			—			—			—
Total benefit cost (gain)	$	1		$	2		$	(1	)	$	(1	)



	Pension Benefits						Post-employment Benefits
	Six Months Ended June 30,
(amounts in millions)	2014			2013			2014			2013
Service cost	$	1		$	2		$	—		$	1
Interest cost	2			5			1			2
Expected return on plan assets	(2		)	(7		)	(2		)	(3		)
Amortization of:
Prior service cost	—			—			(2		)	(4		)
Actuarial gain	—			4			2			2
Net periodic benefit cost (gain)	1			4			(1		)	(2		)
Settlements	2			—			—			—
Total benefit cost (gain)	$	3		$	4		$	(1	)	$	(2	)

In addition to the above net periodic benefit cost for pension and post-employment plans, we were allocated less than $1 million and approximately $1 million in net periodic benefit costs for pension and post-employment plans from Ameren Services employees doing work on our behalf during the three and six months ended June 30, 2013, respectively.

ILLINOIS POWER GENERATING COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2014 and 2013

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 IPR, 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 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, fixed capacity payments 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.

We are organized into a ring-fenced group 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. These provisions restrict the ability to move cash out of Genco without meeting certain requirements as set forth in the governing documents.

At June 30, 2014, our liquidity consisted of $182 million cash on hand. As previously discussed, due to the ring-fenced nature of IPH, 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.

Operating Activities

Historical Operating Cash Flows. Cash flow provided by operating activities totaled $18 million for the six months ended June 30, 2014. During the period, we had sources of $19 million primarily due to the operation of our power generation facilities, partially offset by $4 million of increased collateral postings to satisfy our counterparty collateral demands.

Cash flow provided by operating activities totaled $54 million for the six months ended June 30, 2013. During the period, our power generation business provided cash of $91 million primarily due to the operation of our power generation facilities, $68 million in negative changes due to decreased net deferred tax liabilities and $31 million in positive changes in working capital.

Future Operating Cash Flows. Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of power, the prices of coal and their correlation to power prices, collateral requirements, the value of capacity and ancillary services, the run time of our generating facilities, the effectiveness of our commercial strategy and legal, environmental and regulatory requirements.

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 at June 30, 2014 and December 31, 2013 were $5 million and $1 million, respectively. Collateral postings increased from December 31, 2013 to June 30, 2014 primarily due to fuel and other commodity purchases being executed with counterparties.

Investing Activities

We had capital expenditures of approximately $26 million and $29 million during the six months ended June 30, 2014 and 2013, respectively.

Other Investing Activities. During the six months ended June 30, 2014, we had no other investing activities. During the six months ended June 30, 2013, there was an $100 million cash inflow from the sale of the Gas-Fired Facilities to Medina Valley and a $125 million cash outflow for the repayment of net money pool advances. Please read Note 1—Summary of Significant Accounting Policies in our Form 10-K for further discussion.

Financing Activities

Historical Cash Flow from Financing Activities. During each of the six months ended June 30, 2014 and 2013, we had no cash flow from financing activities.

Financing Trigger Events. Our debt instruments and certain of our other financial obligations and all 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:



	Required Ratio	Actual Ratio
Restricted payment interest coverage ratio (1)	≥1.75	1.51
Additional indebtedness interest coverage ratio (2)	≥2.50	1.51
Additional indebtedness debt-to-capital ratio (2)	≤60%	53%

__________________________________________


(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.

Based on June 30, 2014 calculations, our interest coverage ratios are less than the minimum ratios required for us to pay dividends and borrow additional funds from external, third-party sources. Based on our projections, we expect our interest coverage ratios to be less than the minimum ratios required for us to pay dividends and incur additional third-party indebtedness until at least 2016.

Please read Note 8—Debt for further discussion.

Credit Ratings

Our credit rating status is currently “non-investment grade” and our current ratings are as follows:



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

RESULTS OF OPERATIONS

Overview

In this section, we discuss our results of operations for the three and six months ended June 30, 2014 and 2013. At the end of this section, we have included our business outlook. 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.

Genco has a PSA with IPM, whereby it agreed to sell and IPM agreed to purchase all of the capacity and energy available from its generation fleet. IPM entered into a similar PSA with IPRG. Under the PSAs, revenues allocated between Genco and IPRG are based on reimbursable expenses and generation of each entity. Additionally, the revenues allocated include settled values of derivative instruments entered into by IPM to hedge commodity exposure related to Genco and IPRG generation.

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 are key factors that we seek to control and to optimize our results of operations, financial position and liquidity.

Consolidated Summary Financial Information — Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

The following table provides summary financial data regarding our consolidated results of operations for the three months ended June 30, 2014 and 2013, respectively:



	Three Months Ended June 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2014			2013			Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Revenues	$	138		$	181		$	(43	)	(24	)%
Cost of sales, excluding depreciation expense	(105		)	(139		)	34			24	%
Gross margin	33			42			(9		)	(21	)%
Operating and maintenance expense	(44		)	(54		)	10			19	%
Impairment and other charges	—			5			(5		)	(100	)%
Depreciation and amortization	(24		)	(18		)	(6		)	(33	)%
Operating loss	(35		)	(25		)	(10		)	(40	)%
Interest expense	(10		)	(10		)	—			—	%
Loss before income taxes	(45		)	(35		)	(10		)	(29	)%
Income tax benefit	18			13			5			38	%
Net loss	(27		)	(22		)	(5		)	(23	)%
Less: Net income attributable to noncontrolling interest	—			—			—			—	%
Net loss attributable to Illinois Power Generating Company	$	(27	)	$	(22	)	$	(5	)	(23	)%

Discussion of Consolidated Results of Operations

Revenues. Revenues decreased by $43 million from $181 million for the three months ended June 30, 2013 to $138 million for the three months ended June 30, 2014. The decrease is primarily due to $40 million of power sales to the DOE during 2013 that were not present in three months ended June 30, 2014 and $26 million in lower revenues received through the PSA as a result of a lower net price per MWh. These decreases were offset by an increase of $21 million due to higher sales volumes and $4 million of mark-to-market losses on derivative contracts included in the three months ended June 30, 2013 compared to less than $1 million of mark-to-market derivative gains for the three months ended June 30, 2014.

Cost of Sales. Cost of sales decreased by $34 million from $139 million for the three months ended June 30, 2013 to $105 million for the three months ended June 30, 2014. The decrease is primarily due to $40 million of power purchases to supply a DOE contract and $4 million of fuel expense related to generation from CTs in 2013 that were not present in the three months ended June 30, 2014 and $6 million in lower average fuel price per MWh generated, partially offset by an increase in fuel expense of $14 million as a result of higher generation volumes.

Operating and Maintenance Expense. Operating and maintenance expense decreased by $10 million from $54 million for the three months ended June 30, 2013 to $44 million for the three months ended June 30, 2014. The decrease is primarily due to lower maintenance costs related to extensive boiler repairs at Coffeen and Newton in the three months ended June 30, 2013 as compared to the three months ended June 30, 2014 and the absence of expenses related to the Gas-Fired Facilities, which were sold in October 2013. The decreases were offset by higher overhead and common charges.

Impairment and Other Charges. Impairment and other charges were a positive $5 million for the three months ended June 30, 2013, which was due to a reduction in the carrying value of the Gas-Fired Facilities as a result of derivative market value losses. There was no similar activity during the three months ended June 30, 2014 as the Gas-Fired Facilities were sold in October 2013.

Depreciation and Amortization. Depreciation and amortization increased by $6 million from $18 million for the three months ended June 30, 2013 to $24 million for the three months ended June 30, 2014. The increase is primarily due to $8 million as a result of a change in the depreciable lives of the Genco assets at the IPH acquisition date, partially offset by a decrease of $2 million as a result of the removal of the Gas-Fired Facilities in 2013 due to held for sale accounting.

Income Tax Benefit. We reported an income tax benefit from continuing operations of $18 million and $13 million for the three months ended June 30, 2014 and June 30, 2013, respectively. The increase in the benefit is related to the increase in our pretax loss when comparing the two periods.

Consolidated Summary Financial Information — Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

The following table provides summary financial data regarding our consolidated results of operations for the six months ended June 30, 2014 and 2013, respectively:



	Six Months Ended June 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2014			2013			Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Revenues	$	318		$	375		$	(57	)	(15	)%
Cost of sales, excluding depreciation expense	(219		)	(270		)	51			19	%
Gross margin	99			105			(6		)	(6	)%
Operating and maintenance expense	(83		)	(90		)	7			8	%
Impairment and other charges	—			(202		)	202			100	%
Depreciation and amortization	(48		)	(42		)	(6		)	(14	)%
Operating loss	(32		)	(229		)	197			86	%
Interest expense	(20		)	(21		)	1			5	%
Loss before income taxes	(52		)	(250		)	198			79	%
Income tax benefit	21			99			(78		)	(79	)%
Net loss	(31		)	(151		)	120			79	%
Less: Net income attributable to noncontrolling interest	2			—			2			100	%
Net loss attributable to Illinois Power Generating Company	$	(33	)	$	(151	)	$	118		78	%

Discussion of Consolidated Results of Operations

Revenues. Revenues decreased by $57 million from $375 million for the six months ended June 30, 2013 to $318 million for the six months ended June 30, 2014. The decrease is primarily due to $40 million of power sales to the DOE during the six months ended June 30, 2013 that were not present in the six months ended June 30, 2014 and $27 million in lower revenues received through the PSA as the result of a lower net price per MWh. The decrease was further due to $2 million of mark-to-market gains on derivative contracts included in the six months ended June 30, 2013 revenues compared to less than $1 million of mark-to-market derivative activity for the six months ended June 30, 2014. The decreases were partially offset by an increase of $16 million due to higher sales volumes in the six months ended June 30, 2014.

Cost of Sales. Cost of sales decreased by $51 million from $270 million for the six months ended June 30, 2013 to $219 million for the six months ended June 30, 2014. The decrease is primarily due to $14 million in lower average fuel price per MWh generated and $40 million of power purchases to supply a DOE contract and $13 million of fuel expense related to generation from CTs in 2013 that were not present in the six months ended June 30, 2014, offset by an increase in fuel expense of $15 million as a result of higher generation volumes.

Operating and Maintenance Expense. Operating and maintenance expense decreased by $7 million from $90 million for the six months ended June 30, 2013 to $83 million for the six months ended June 30, 2014. The decrease is primarily due to lower maintenance costs related to extensive boiler repairs at Coffeen and Newton in the six months ended June 30, 2013 as compared to the six months ended June 30, 2014 and the absence of expenses related to the Gas-Fired Facilities, which were sold in October 2013. The decreases were partially offset by higher overhead and common charges, an EEI pension plan settlement for the six months ended June 30, 2014 and a gain on the sale of Meredosia assets in the six months ended June 30, 2013 with no similar activity in the same period of 2014.

Impairment and Other Charges. Impairment and other charges were $202 million for the six months ended June 30, 2013, which was due to a pretax charge to earnings to reflect the impairment of the Gas-Fired Facilities, which were held for sale during the period. There were no such charges during the six months ended June 30, 2014 as the Gas-Fired Facilities were sold in October 2013.

Depreciation and Amortization. Depreciation and amortization increased by $6 million from $42 million for the six months ended June 30, 2013 to $48 million for the six months ended June 30, 2014. The increase is primarily due to $14 million as a result of a change in the depreciable lives of the Genco assets at the IPH acquisition date, partially offset by a decrease of $8 million as a result of the removal of the Gas-Fired Facilities in 2013 due to held for sale accounting.

Income Tax Benefit. We reported an income tax benefit from continuing operations of $21 million and $99 million for the six months ended June 30, 2014 and June 30, 2013, respectively. The decrease in the benefit is related to the decrease in our pretax loss when comparing the two periods.

Outlook

As of August 1, 2014, our expected coal requirements are fully contracted and 94 percent priced in 2014. Our forecasted coal requirements for 2015 are 56 percent contracted and 38 percent priced. Our transportation requirements are fully contracted and priced for the next several years. We look to procure and price additional fuel opportunistically.

Through IPM, we commercialize our assets through a combination of physical participation in the MISO markets and bilateral capacity sales. For the 2013-2014 planning year, capacity cleared at $1.05 per MW-day for all zones. This low clearing price was likely caused by excess capacity conditions prevailing in MISO for the term of the planning year. On April 14, 2014, MISO released the results of the Planning Year 2014-2015 capacity auction. Local Resource Zone 4 cleared at $16.75 per MW-day. In the future, the potential retirement of marginal MISO coal capacity due to poor economics or expected environmental mandates and confirmed future capacity exports from MISO to PJM could also increase MISO capacity and energy pricing.

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. Through IPM, we have sold capacity volumes for the 2015-2016 and 2016-2017 planning years. The most recent PJM auction for the 2017-2018 planning year cleared at $120 per MW-day, and we sold approximately 16 percent of our capacity in that auction. We have also secured an additional 240 MW of transmission to PJM which will clear in the future incremental auctions.

Environmental and Regulatory Matters

Please read Environmental Matters in Note 10—Commitments and Contingencies in our Form 10-K for the period ended December 31, 2013 and Item 2. Outlook-Environmental Matters in our Form 10-Q for the period ended March 31, 2014 for a detailed discussion of our environmental matters.

Mercury/ HAPs. In July 2014, various parties filed petitions for certiorari with the U.S. Supreme Court seeking review of the U.S. Court of Appeals for the District of Columbia Circuit’s decision upholding the Mercury and Air Toxics Standards rule for EGUs. Given the air emission controls already employed, we expect that our facilities will be in compliance with the Mercury and Air Toxic Standards rule emission limits without the need for significant additional investment. We continue to monitor the performance of our units and evaluate approaches to optimizing compliance strategies.

Cross-State Air Pollution Rule. On April 29, 2014, the U.S. Supreme Court issued a decision in EPA v. EME Homer City Generation, L.P. upholding the CSAPR. The Court also remanded the case to the Court of Appeals for the District of Columbia Circuit for further proceedings consistent with its decision. On June 26, 2014, the EPA filed a motion in the court of appeals asking

the court to lift the stay of the CSAPR such that Phase I of the CSAPR would begin on January 1, 2015. Pending further action by the court, the CAIR remains in effect. If the CSAPR were to be reinstated in 2015, we would not expect to incur any material capital compliance costs given the SO₂ and NO_xemission controls currently installed and operating on our affected facilities.

IPH Variance. In January 2014, an environmental group filed a petition for review in the Illinois Fourth District Appellate Court of the IPCB’s November 2013 decision and order granting IPH a variance to extend the applicable compliance dates for MPS SO₂ emission limits through December 31, 2019, subject to certain conditions. On January 17, 2014, IPH filed a Motion to Dismiss and, on February 24, 2014, the Fourth District Appellate Court granted IPH’s motion and dismissed the appeal. On April 1, 2014, the environmental group filed a petition for leave to appeal the Appellate Court’s decision with the Illinois Supreme Court. On May 5, 2014, we filed an answer opposing review by the Illinois Supreme Court. We believe the variance was properly granted and that the Appellate Court’s judgment dismissing the petition for review was proper. We will vigorously defend our position. Please read Note 9—Commitments and Contingencies for further discussion.

Cooling Water Intake Structures. On May 16, 2014, the EPA issued its final rule for cooling water intake structures at existing facilities. The final rule establishes seven alternatives for complying with best technology available requirement for reducing impingement mortality, including modified traveling screens, closed-cycle cooling, a numeric impingement standard, or a site-specific determination. For entrainment, the permitting authority is required to establish a case-by-case standard considering several factors, including social costs and benefits. The rule does not require closed-cycle cooling and provides that closed-cycle cooling includes impoundments in waters of the United States that were created for the purpose of serving as part of a cooling water system. The rule also includes provisions to address endangered and threatened species. Compliance with the final rule’s entrainment and impingement mortality standards is required as soon as practicable, but will vary by site depending on several different factors, including determinations made by the state permitting authority and the timing of renewal of a facility’s NPDES permit. In general, compliance is expected to be required over the period 2018 to 2022.

Our ultimate compliance approach with the final rule, at any particular facility will depend on numerous factors, including implementation by the relevant state permitting authority, the results of technology, biological and other required studies, and the applicable compliance deadline.

Coal Combustion Residuals. The EPA is expected to issue a CCR final rule in late 2014 and intends to align its steam electric effluent limitation guidelines rule with the CCR rule. We are currently evaluating these proposed regulations 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 proposed regulations, which could be material, if such regulations are adopted.

Federal Regulation of Greenhouse Gases. On June 2, 2014, the EPA issued a proposed rule to reduce CO₂ emissions from existing fossil-fuel EGUs. The proposed rule, known as the Clean Power Plan, would not directly establish emission rates for fossil-fuel EGUs, but instead would require states to meet state-specific CO₂ emissions rate targets (expressed as weighted-average pounds of CO₂ per net MWh), beginning with an interim rate in 2020 and a final rate to be achieved by 2030. Overall, the EPA expects the proposal would reduce CO₂ emissions from the power generation sector by 30 percent nationwide from 2005 levels.

Under the proposed rule, each state would be required to reduce CO₂ emissions rates from fossil-fuel EGUs to varying degrees. The emission rate targets are based on each state’s unique mix of historical fossil-fuel EGU CO₂ emissions and projected emissions, reflecting individual state regulatory programs such as renewable energy mandates and energy efficiency standards. The EPA intends for states to take the lead in determining how to reduce CO₂ emissions. The proposed state-specific emissions targets are based on four approaches to CO₂ reduction, namely, heat rate improvements at existing solid-fuel EGUs, greater use of natural gas in place of the most carbon intensive affected EGUs, greater use of low- or zero-carbon generation units, and demand side energy efficiency measures that reduce the amount of generation. States would choose how to meet their specific emissions targets and could do so by either meeting the specified target emissions rate or establishing an equivalent mass-based cap-and-trade program. States also would have the flexibility to comply using their own programs or by joining a multi-state approach to compliance. States generally would be required to submit implementation plans detailing their CO₂ reduction plans by June 2016.

On June 2, 2014, the EPA also issued proposed CO₂ emission standards for modified and reconstructed power plants. For modified utility boilers and IGCC units, the EPA proposed two alternatives standards. Under the first alternative, modified sources would be required to meet a limit determined by the unit’s best historical annual CO₂ emission rate since 2002, plus an additional two percent reduction. However, the limit would be no lower than 1,900 lbs CO₂/MWh for sources with heat input greater than 2,000 MMBtu/hr or 2,100 lbs CO₂/MWh for sources with heat input less than or equal to 2,000 MMBtu/hr. Under the second alternative, the applicable emissions limit would depend on when the modification occurs. If the source is modified before it becomes subject to a Clean Power Plan, the first alternative identified above would apply. If the source is modified after it becomes subject to a Clean Power Plan, the source must meet a unit-specific limit determined by the implementing authority based on the results of an energy efficiency improvement audit. The proposed CO₂ emission standard for reconstructed utility

boilers and IGCC units is 1,900 lbs CO₂/MWh for sources with heat input greater than 2,000 MMBtu/hr or 2,100 lbs CO₂/MWh for sources with heat input less than or equal to 2,000 MMBtu/hr. The proposed standard for modified or reconstructed natural gas fired stationary combustion turbines is identical to the proposed NSPS for such units (e.g., 1,000 lbs CO₂/MWh-gross).

The EPA anticipates issuing final rules for the Clean Power Plan and modified/reconstructed power plants in June 2015. We continue to analyze the proposed rules, the potential impacts on our power generation facilities, and how the proposals 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 rulemakings 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.

Climate Change Litigation. On June 23, 2014, the U.S. Supreme Court issued a decision in the litigation involving several EPA rules concerning the regulation of GHG emissions under the CAA's PSD and Title V permitting programs. The Court held that the EPA may not impose PSD or Title V permitting requirements on facilities based solely on emissions of GHGs. In doing so, the Court also invalidated the EPA’s Tailoring Rule, which had modified the emissions permitting thresholds for PSD and Title V as established in the CAA to account for GHGs, holding that the EPA could not change the statutory applicability terms of the CAA. However, the Court also concluded that the EPA may impose BACT requirements on GHG emissions if a facility is otherwise subject to BACT for emissions of other pollutants. The Court also determined that the EPA may establish a de minimis threshold below which BACT would not be required for GHG emissions, but left it open to the EPA to justify the appropriate threshold.

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 believe or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment on 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 and 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:

•

expectations regarding 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 to which we are, or could become, subject;


•	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 gas prices, if any;


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


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


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


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


•	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;


•	beliefs regarding impairments of long-lived assets;


•	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;


•	beliefs and assumptions about weather and general economic conditions;


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


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


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


•	the timing and anticipated benefits to be achieved through our company-wide savings improvement programs, including our PRIDE initiative; and


•	expectations regarding performance standards and capital and maintenance expenditures.

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 “Accounting Matters” 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, 2013 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 months ended June 30, 2014.

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 CEO and our 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 30, 2014.

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 30, 2014.

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS

Please read Note 9—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 Part I—Item 1A—Risk Factors, of our Form 10-K for factors, risks and uncertainties that may affect future results.

Item 6—EXHIBITS

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



Exhibit Number		Description
10.1		Waiver and Amendment No. 1 to Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and Union Bank, N.A. (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2014 of Dynegy Inc. File No. 1-33443).
**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.

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 13, 2014	By:	/s/ CLINT C. FREELAND
			Clint C. Freeland Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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Illinois Power Generating Co Reports

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