Illinois Power Generating Co - FORM 10-Q - November 10, 2016

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EX-32.2 - CHIEF FINANCIAL OFFICER 906 CERTIFICATION - Illinois Power Generating Cogenco-2016930xex322.htm
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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 September 30, 2016
 
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 November 10, 2016, 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
 
 
 
 
 
 
Item 1.
 
 
 
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
 
 
 
 
 
Item 1.
Item 1A.
Item 6.
 
 





DEFINITIONS
As used in this Form 10-Q, the abbreviations contained herein have the meanings set forth below. 
CAA
 
Clean Air Act
EPA
 
Environmental Protection Agency
FERC
 
Federal Energy Regulatory Commission
IMA
 
In-market Asset Availability
IPH
 
IPH, LLC (formerly known as Illinois Power Holdings, LLC)
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


i



PART I. FINANCIAL INFORMATION
Item 1—FINANCIAL STATEMENTS

ILLINOIS POWER GENERATING COMPANY
 CONSOLIDATED BALANCE SHEETS
(unaudited) (in millions, except share data)
 
September 30, 2016
 
December 31, 2015
ASSETS
 
 
 
Current Assets
 
 
 
Cash
$
84

 
$
61

Restricted cash
6

 
—

Accounts receivable, affiliates
63

 
54

Accounts receivable
7

 
8

Inventory
96

 
133

Prepayments and other current assets
7

 
6

Total Current Assets
263

 
262

Property, Plant and Equipment, Net
207

 
937

Other assets
27

 
27

Total Assets
$
497

 
$
1,226

 
 
 
 
LIABILITIES AND STOCKHOLDER’S EQUITY
 
 
 
Current Liabilities
 
 
 
Accounts payable
$
22

 
$
26

Accounts payable, affiliates
40

 
18

Taxes accrued
7

 
10

Accrued interest
25

 
10

Accrued liabilities and other current liabilities
8

 
9

Total Current Liabilities
102

 
73

   Long-term debt
821

 
820

Other Liabilities
 
 
 
Deferred income taxes, net
1

 
119

Asset retirement obligations
50

 
49

Other long-term liabilities
25

 
24

    Total Liabilities
999

 
1,085

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
542

 
542

Accumulated other comprehensive loss, net of tax
(10
)
 
(10
)
Retained earnings
(1,037
)
 
(396
)
Total Illinois Power Generating Company Stockholder’s Equity
(505
)
 
136

Noncontrolling interest
3

 
5

Total Equity
(502
)
 
141

Total Liabilities and Equity
$
497

 
$
1,226

See the notes to consolidated financial statements.

1



                         
ILLINOIS POWER GENERATING COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited) (in millions)
 
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2016
 
2015
 
2016
 
2015
Revenues
 
$
147

 
$
146

 
$
343

 
$
420

Cost of sales, excluding depreciation expense
 
(85
)
 
(88
)
 
(212
)
 
(265
)
Gross margin
 
62

 
58

 
131

 
155

Operating and maintenance expense
 
(34
)
 
(29
)
 
(93
)
 
(104
)
Impairment and other charges
 
(69
)
 
(855
)
 
(736
)
 
(855
)
Depreciation and amortization expense
 
(8
)
 
(25
)
 
(27
)
 
(75
)
General and administrative expense
 
(9
)
 
(4
)
 
(19
)
 
(17
)
Operating loss
 
(58
)
 
(855
)
 
(744
)
 
(896
)
Interest expense
 
(13
)
 
(10
)
 
(32
)
 
(29
)
Other income and expense, net
 
1

 
—

 
15

 
—

Loss before income taxes
 
(70
)
 
(865
)
 
(761
)
 
(925
)
Income tax benefit
 
4

 
348

 
118

 
373

Net loss
 
(66
)
 
(517
)
 
(643
)
 
(552
)
Less: Net income (loss) attributable to noncontrolling interest
 
—

 
2

 
(2
)
 
(1
)
Net loss attributable to Illinois Power Generating Company
 
$
(66
)
 
$
(519
)
 
$
(641
)
 
$
(551
)
 
 
 
 
 
 
 
 
 

See the notes to consolidated financial statements.

2



ILLINOIS POWER GENERATING COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(unaudited) (in millions)

 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2016
 
2015
 
2016
 
2015
Net income (loss)
 
$
(66
)
 
$
(517
)
 
$
(643
)
 
$
(552
)
Other comprehensive income (loss) before reclassifications:
 
 
 
 
 
 
 
 
Actuarial gain due to pension plan remeasurement (net of tax benefit of zero, $5, zero, and $5 for each respective period)
 
—

 
8

 
—

 
8

Amounts reclassified from accumulated other comprehensive loss:
 
 
 
 
 
 
 
 
Reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges (net of tax of zero for each respective period)
 
—

 
1

 
1

 
1

Amortization of unrecognized prior service credit (net of tax of zero for each respective period)
 
—

 
—

 
(1
)
 
—

Other comprehensive income (loss), net of tax
 
—

 
9

 
—

 
9

Comprehensive income (loss)
 
(66
)
 
(508
)
 
(643
)
 
(543
)
Less: Comprehensive income (loss) attributable to noncontrolling interest
 
—

 
3

 
(2
)
 
—

Total comprehensive income (loss) attributable to Illinois Power Generating Company
 
$
(66
)
 
$
(511
)
 
$
(641
)
 
$
(543
)

See the notes to consolidated financial statements.


3




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

 
Nine Months Ended September 30,
 
2016
 
2015
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net loss
$
(643
)
 
$
(552
)
Adjustments to reconcile net loss to net cash flows from operating activities:
 
 
 
Impairment of long-lived assets
736

 
855

Depreciation expense
27

 
75

Gain on sale of assets, net
(14
)
 
—

Deferred income taxes and investment tax credits, net
(118
)
 
(373
)
Other
3

 
8

Changes in working capital:
 
 
 
Accounts receivable, net
(8
)
 
56

Inventory
37

 
(15
)
Prepayments and other current assets
(1
)
 
(3
)
Restricted cash
(6
)
 
—

Accounts payable and accrued liabilities
29

 
(1
)
Other
—

 
(5
)
Net cash provided by operating activities
42

 
45

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Capital expenditures
(33
)
 
(43
)
Proceeds on sale of assets, net
14

 
—

Net cash used in investing activities
(19
)
 
(43
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Net cash provided by financing activities
—

 
—

Net increase in cash
23

 
2

Cash, beginning of year
61

 
126

Cash, end of period
$
84

 
$
128


See the notes to consolidated financial statements.


4
ILLINOIS POWER GENERATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended September 30, 2016 and 2015

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. Certain prior period amounts in our consolidated financial statements have been reclassified to conform to current year presentation. 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, 2015, filed with the SEC on March 28, 2016, 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. Our $825 million of senior notes (the “Senior Notes”) are non-recourse to Dynegy.
As a result of continued weak energy prices, unsold capacity volumes, on-going required maintenance and environmental expenditures as well as consideration of a $300 million debt maturity in 2018, during the second quarter of 2016 we engaged advisors and began a strategic review.  While our projected future cash flow is sufficient to cover our obligations through December 31, 2016, we may not have sufficient future operating cash flow to satisfy our debt maturity in 2018, absent a debt refinancing or restructuring. Therefore, there is substantial doubt about our ability to continue as a going concern. On October 14, 2016, we entered into a restructuring support agreement (the “RSA”) with Dynegy and an ad hoc group of our bondholders (“Ad Hoc Group”) to restructure our Senior Notes either through (a) an out-of-court exchange (the “Exchange Offer”) of our Senior Notes or (b) if the conditions to the Exchange Offer are not satisfied or waived, a pre-packaged plan of reorganization for Genco (the “Plan”) filed in a Chapter 11 case under title 11 of the United States Code (the “Bankruptcy Code”). On November 7, 2016, we launched a restructuring transaction with Dynegy with respect to our Senior Notes (the “Restructuring”) in accordance with the terms of the RSA. See Note 13—Subsequent Events.
Note 2—Accounting Policies
The accounting policies followed by the Company are set forth in Note 2—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 nine months ended September 30, 2016, with the exception of the addition of the restricted cash policy noted below.
Use of Estimates. 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.
Restricted Cash.  Restricted cash represents cash that is not readily available for general purpose cash needs. Restricted cash is classified as a current or long-term asset based on the timing and nature of when or how the cash is expected to be used or when the restrictions are expected to lapse. As of September 30, 2016, we had restricted cash of $6 million classified as current assets related to cash deposits associated with collateral for operating activities.

5
ILLINOIS POWER GENERATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended September 30, 2016 and 2015

Accounting Standards Adopted During the Current Period
Hybrid Financial Instruments. In November 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-16-Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or Equity. The amendments in this ASU clarify how current GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically, the amendments clarify that an entity should consider all relevant terms and features, including the embedded derivative feature being evaluated for bifurcation, in evaluating the nature of the host contract. Furthermore, the amendments clarify that no single term or feature would necessarily determine the economic characteristics and risks of the host contract. Rather, the nature of the host contract depends upon the economic characteristics and risks of the entire hybrid financial instrument. The amendments in this ASU also clarify that, in evaluating the nature of a host contract, an entity should assess the substance of the relevant terms and features (i.e., the relative strength of the debt-like or equity-like terms and features given the facts and circumstances) when considering how to weigh those terms and features. The adoption of this ASU on January 1, 2016, did not have an impact on our unaudited consolidated financial statements.
Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update.
In August 2015, the FASB issued ASU 2015-15-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU further clarify the guidance provided in ASU 2015-03 to include the presentation of debt issuance costs in relation to line-of-credit arrangements. The amendments state these costs 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.
We adopted these ASUs on January 1, 2016, on a retrospective basis affecting presentation on the unaudited consolidated balance sheet for all periods presented. Accordingly, we reclassified unamortized debt issuance costs of $1 million from Prepayments and other current assets and $3 million from Other assets to Long-term debt within our unaudited consolidated balance sheet as of December 31, 2015.
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.  The adoption of this ASU on January 1, 2016, did not have an impact on our unaudited consolidated financial statements.
Accounting Standards Not Yet Adopted
Statement of Cash Flows. In August 2016, the FASB issued ASU 2016-15-Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. To reduce current and future diversity in practice, the amendments in this ASU provide guidance for several cash flow classification issues identified where current GAAP is either unclear or does not include specific guidance. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements.
Credit Losses. In June 2016, the FASB issued ASU 2016-13-Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The amendments in this ASU require the measurement of all expected credit losses for financial assets, which include trade receivables, held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements.
Compensation. In March 2016, the FASB issued ASU 2016-09-Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this ASU simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance in this ASU is effective for fiscal years, and interim

6
ILLINOIS POWER GENERATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended September 30, 2016 and 2015

periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements.    
Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The amendments in this ASU will mainly require lessees to recognize lease assets and lease liabilities, for those leases classified as operating leases under GAAP, in their balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements.
Going Concern. In August 2014, the FASB issued ASU 2014-15-Presentation of Financial Statements-Going Concern (Subtopic 205-40). The amendments in this ASU require management, in connection with preparing financial statements for each annual and interim reporting period, to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). Currently, there is no guidance in GAAP about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern or to provide related footnote disclosures. The amendments in this ASU provide that guidance. In doing so, the amendments should reduce diversity in the timing and content of footnote disclosures. The guidance in this ASU is effective for fiscal years ending after December 15, 2016, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements.
Revenue from Contracts with Customers. In May 2014, the FASB and International Accounting Standards Board jointly issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU, and subsequently issued amendments to the standard, develop a common revenue standard for GAAP and International Financial Reporting Standards by removing inconsistencies and weaknesses in revenue requirements, providing a more robust framework for addressing revenue issues, improving comparability of revenue recognition practices, providing more useful information to users of financial statements, and simplifying the preparation of financial statements. The guidance in this ASU and its amendments 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 evaluating this ASU; however, we do not anticipate that the adoption of this ASU will have a material impact on our unaudited consolidated financial statements.
Note 3—Risk Management, Derivatives and Financial Instruments
There were no derivative instruments on our unaudited consolidated balance sheet as of September 30, 2016, and December 31, 2015.
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 Loss (“AOCL”) was $3 million and $4 million as of September 30, 2016, and December 31, 2015, 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 currently being amortized out of AOCL into our consolidated statements of operations over a 10-year period that began in April 2008; however, upon the successful completion of our debt restructure or Chapter 11 bankruptcy, the remaining balance of $3 million will be written off. Please see Note 13—Subsequent Events for further discussion on the debt restructure.
Financial Instruments Not Designated as Hedges. There was no impact of mark-to-market gains (losses) on our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016 and 2015.
Note 4—Fair Value Measurements
Non-recurring Measurements. In the second quarter of 2016, as a result of impairment testing, we measured our Newton facility at fair value. Please read Note 7—Property, Plant and Equipment for further discussion. The valuation method used to determine the impairment charge is classified as Level 3 within the fair value hierarchy.

7
ILLINOIS POWER GENERATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended September 30, 2016 and 2015

Fair Value of Financial Instruments.  We have determined the estimated fair value of our financial instruments using available market information and selected valuation methodologies.  Considerable judgment is required in interpreting market data to develop the estimates of fair value.  The use of different market assumptions or valuation methodologies could have a material effect on the estimated fair value amounts.
The carrying values of financial assets and liabilities (cash, accounts receivable, restricted cash, and accounts payable) not presented in the table below approximate fair values due to the short-term maturities of these instruments.  Unless otherwise noted, the fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes as of September 30, 2016 and December 31, 2015, respectively. All fair values presented below are classified within Level 2 of the fair value hierarchy.  Please see Note 13—Subsequent Events.
 
 
September 30, 2016
 
December 31, 2015
(amounts in millions)
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
7.00% Senior Notes Series H, due 2018 (1)
 
$
(300
)
 
$
(119
)
 
$
(299
)
 
$
(204
)
6.30% Senior Notes Series I, due 2020 (1)
 
$
(249
)
 
$
(99
)
 
$
(249
)
 
$
(148
)
7.95% Senior Notes Series F, due 2032 (1)
 
$
(272
)
 
$
(107
)
 
$
(272
)
 
$
(162
)
__________________________________________
(1)
Combined carrying amounts include unamortized discounts and debt issuance costs of $4 million and $5 million as of September 30, 2016 and December 31, 2015, respectively. Please read Note 8—Debt for further discussion.
Note 5—Accumulated Other Comprehensive Loss
Changes in accumulated other comprehensive loss, net of tax, by component are as follows:
 
 
Nine Months Ended September 30,
(amounts in millions)
 
2016
 
2015
Beginning of year
 
$
(10
)
 
$
(16
)
Other comprehensive income (loss) before reclassifications:
 
 
 
 
Actuarial gain due to pension plan remeasurement (net of tax benefit of zero and $5, respectively)
 
—

 
5

Amounts reclassified from accumulated other comprehensive loss:
 
 
 
 
Reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges (net of tax of zero and zero, respectively) (1)
 
1

 
1

Amortization of unrecognized prior service credit (net of tax of zero and zero, respectively) (2)
 
(1
)
 
—

Net current period other comprehensive income (loss), net of tax
 
—


6

End of period
 
$
(10
)

$
(10
)
_______________________________________
(1)
Amount related to the reclassification of mark-to-market losses on cash flow hedging activities and was recorded in Interest expense on our unaudited consolidated statements of operations. Please read Note 3—Risk Management, Derivatives and Financial Instruments for further discussion.
(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.
Note 6—Inventory
A summary of our inventories is as follows:
(amounts in millions)
 
September 30, 2016
 
December 31, 2015
Materials and supplies
 
$
30

 
$
30

Coal
 
65

 
102

Fuel oil
 
1

 
1

Total
 
$
96

 
$
133


8
ILLINOIS POWER GENERATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended September 30, 2016 and 2015

Note 7—Property, Plant and Equipment
A summary of our property, plant and equipment is as follows:
(amounts in millions)
 
September 30, 2016
 
December 31, 2015
Power generation
 
$
510

 
$
1,511

Building and improvements
 
51

 
212

Office and other equipment
 
22

 
27

Property, plant and equipment
 
583

 
1,750

Accumulated depreciation
 
(376
)
 
(813
)
Property, plant and equipment, net
 
$
207

 
$
937

Impairments
Newton. In the second quarter of 2016, due to the recent MISO auction results and the impact of the shutdown of one of our Newton facility units, we performed an impairment analysis on our plants. We performed step one of the impairment analysis using undiscounted cash flows for the estimated useful lives of the facilities and determined the book value of the Newton facility would not be recovered. We performed step two of the impairment analysis using a discounted cash flow model, utilizing a 13 percent discount rate, and assuming normal operations for the estimated useful lives of the facilities. For the model, gross margin was based on forward commodity market prices obtained from third party quotations for the years 2016 through 2018. For the years 2019 through 2025, we used commodity and capacity price curves developed internally utilizing supply and demand factors. We also used management’s forecasts of operations and maintenance expense, general and administrative expense, and capital expenditures for the years 2016 through 2025 and assumed a 2.5 percent growth rate thereafter, based upon management’s view of future conditions. The model resulted in a fair value of the Newton facility of $71 million, resulting in an impairment charge of $667 million recorded to Impairments in our unaudited consolidated statements of operations for the nine months ended September 30, 2016. The valuation is classified as Level 3 within the fair value hierarchy.
On September 2, 2016, IPH and Ameren Energy Medina Valley Cogen, LLC filed a motion with the Illinois Pollution Control Board (“IPCB”) to terminate the variance from the SO2 annual emission rate limits provided in the Illinois Multi-Pollutant Standards (“MPS”). IPH retired Newton Unit 2 on September 15, 2016. This retirement, along with the use of dispatch management, will allow IPH to continue to comply with the MPS SO2 limits, thereby eliminating the need for the variance. As a result, the flue gas desulfurization (“FGD”) systems construction project at our Newton generation facility was terminated. On October 27, 2016, the IPCB granted the motion to terminate the variance. Capitalized costs not yet placed into service related to the project of $69 million were written-off and recorded to Impairments in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016.
Coffeen. During the third quarter of 2015, we impaired the book value of our Coffeen facility and recorded an impairment charge of $855 million to Impairments in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2015. See Note 3—Impairments in our Form 10-K for further discussion.
Note 8—Debt
A summary of our long-term debt is as follows:
(amounts in millions)
 
September 30, 2016
 
December 31, 2015
Unsecured notes:
 
 
 
 
7.00% Senior Notes Series H, due 2018 (1)
 
$
300

 
$
300

6.30% Senior Notes Series I, due 2020 (1)
 
250

 
250

7.95% Senior Notes Series F, due 2032 (1)
 
275

 
275

 
 
825

 
825

Unamortized discount and debt issuance costs (2)
 
(4
)
 
(5
)
Total Long-term debt (3)
 
$
821

 
$
820


9
ILLINOIS POWER GENERATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended September 30, 2016 and 2015

_______________________________________
(1)
On October 14, 2016, we entered into the RSA with Dynegy and the Ad Hoc Group to restructure our Senior Notes. On November 7, 2016, we launched the Restructuring in accordance with the terms of the RSA. See Note 13—Subsequent Events—Genco Debt Restructure for further discussion.
(2)
Includes $4 million related to the reclassification of unamortized debt issuance costs as of December 31, 2015. Please read Note 2—Accounting Policies for further discussion.
(3)
Our Senior Notes are non-recourse to Dynegy.
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 September 30, 2016, we were in compliance with the provisions and covenants contained within our indenture. Our indenture also includes provisions that require us to maintain certain interest coverage and debt-to-capital ratios in order for us to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these required ratios:
 
 
Required Ratio
Restricted payment interest coverage ratio (1)
 
≥1.75
Additional indebtedness interest coverage ratio (2)
 
≥2.50
Additional indebtedness debt-to-capital ratio (2)
 
≤60%
_______________________________________
(1)
As of the date of 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 external, third-party sources are included in the definition of indebtedness and are subject to these incurrence tests.
Based on September 30, 2016 calculations, we did not meet the ratios required for us to pay dividends and borrow additional funds from external, third party sources.
Note 9—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, the nature of damages sought, and the probability of success.  Management regularly reviews all new information with respect to such contingencies and adjusts its assessments and estimates of such contingencies accordingly.  Because litigation is subject to inherent uncertainties including unfavorable rulings or developments, it is possible that the ultimate resolution of our legal proceedings could involve amounts that are different from our currently recorded accruals, and that such differences could be material.
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.  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

10
ILLINOIS POWER GENERATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended September 30, 2016 and 2015

Market Monitor for MISO (“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred.  The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies.  Dynegy disputes the allegations and will defend its actions vigorously. Dynegy filed its Answer to these complaints. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff.  Dynegy also responded to this complaint.
On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules, and regulations occurred before or during the PRA (the “Order”). The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation. Further, FERC held a Staff-led technical conference on October 20, 2015, to obtain further information concerning potential changes to the MISO PRA structure going forward, including proposals made by complainants. The technical conference did not address the ongoing Office of Enforcement investigation.
On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions associated with calculating Initial Reference Levels and Local Clearing Requirements, effective as of the 2016-2017 PRA. Under the order, FERC found that the existing tariff provision which bases Initial Reference Levels for capacity supply offers on the estimated opportunity cost of exporting capacity to a neighboring region (for example, PJM) are no longer just and reasonable. Accordingly, FERC required MISO to set the Initial Reference Level for capacity at $0 per MW-day for the 2016-2017 PRA.  Capacity suppliers may also request a facility-specific reference level from the MISO IMM. The order did not address the arguments of the complainants regarding the 2015-2016 PRA, and stated that those issues remain under consideration and will be addressed in a future order.
New Source Review and CAA Matters
New Source Review. Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the New Source Review and New Source Performance Standard provisions under the CAA when the plants implemented modifications. The EPA’s initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment.
CAA Section 114 Information Requests. Commencing in 2005, we received a series of information requests from the EPA pursuant to Section 114(a) of the CAA. The requests sought detailed operating and maintenance history data with respect to the Coffeen, Newton, and Joppa facilities. In August 2012, the EPA issued a Notice of Violation (“NOV”) alleging that projects performed in 1997, 2006, and 2007 at the Newton facility violated Prevention of Significant Deterioration, Title V permitting, and other requirements. The NOV remains unresolved. We believe our defenses to the allegations described in the NOV are meritorious. A decision by the U.S. Court of Appeals for the Seventh Circuit in 2013 held that similar claims older than five years were barred by the statute of limitations. This decision may provide an additional defense to the allegations in the NOV.
Ultimate resolution of any of these CAA matters could have a material adverse impact on our future financial condition, results of operations, and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve these matters.
Groundwater. Groundwater monitoring results indicate that the coal combustion residuals (“CCR”) surface impoundments at the Newton, Coffeen, and Joppa facilities potentially impact onsite groundwater. In 2012, the Illinois EPA (“IEPA”) issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. In April 2015, we submitted an assessment monitoring report to the IEPA 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. In August 2016, the IEPA approved the report.
If remediation measures concerning groundwater are necessary at any of our facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required.

11
ILLINOIS POWER GENERATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended September 30, 2016 and 2015

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.
Environmental Compliance Obligations. On September 2, 2016, IPH and Ameren Energy Medina Valley Cogen, LLC filed a motion with the IPCB to terminate the variance from the SO2 annual emission rate limits provided in the MPS. IPH retired Newton Unit 2 on September 15, 2016. This retirement, along with the use of dispatch management, will allow IPH to continue to comply with the MPS SO2 limits, thereby eliminating the need for the variance. As a result, the FGD systems construction project at our Newton generation facility was terminated. On October 27, 2016, the IPCB granted the motion to terminate the variance.
Indemnifications and Guarantees
In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications, and guarantees.  Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales agreements, and procurement and construction contracts.  Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third-party claims, in which event we will effectively be indemnifying the other party.  Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false.  While there is always the possibility of a loss related to such representations, warranties, indemnifications, and guarantees in our contractual agreements, and such loss could be significant, management considers the probability of loss to be remote.
Guaranty Agreement. Genco has provided an uncapped Guaranty Agreement of certain credit support obligations and tax and environmental indemnification obligations of IPH under a transaction agreement with Ameren Corporation (“Ameren”). Certain of the guaranteed obligations under the Guaranty Agreement will survive indefinitely.
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, 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, 2016
 
December 31, 2015
(amounts in millions)
 
Accounts Receivable, Affiliates
 
Accounts Payable, Affiliates
 
Accounts Receivable, Affiliates
 
Accounts Payable, Affiliates
Power supply agreements
 
$
60

 
$
—

 
$
54

 
$
—

Services agreement
 
—

 
22

 
—

 
5

Tax sharing agreement
 
—

 
1

 
—

 
3

Other (1)
 
3

 
17

 
—

 
10

Total
 
$
63

 
$
40

 
$
54

 
$
18

__________________________________________
(1)
At September 30, 2016 and December 31, 2015, approximately $14 million and $10 million, respectively, of the accounts payable, affiliates balance is comprised of reimbursable employee benefits paid by a Dynegy subsidiary on behalf of Genco.

12
ILLINOIS POWER GENERATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended September 30, 2016 and 2015

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, 2016 and 2015. 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
 
2016
 
2015
 
2016
 
2015
Power supply agreements
 
Revenues
 
$
147

 
$
146

 
$
343

 
$
418

Services agreement
 
Operating and maintenance expense
 
$
7

 
$
7

 
$
23

 
$
26

Power Supply Agreements
Genco has a PSA with Illinois Power Marketing Company (“IPM”), a subsidiary of IPR, whereby IPM purchases all of the capacity and energy available from Genco’s generation fleet. IPM entered into a similar PSA with Illinois Power Resources Generating, LLC (“IPRG”). Under the PSAs, IPM revenues are allocated between Genco and IPRG based on reimbursable expenses and generation of each entity. The reimbursable expenses used in the calculation of revenues allocated under the Genco and IPRG PSAs include operation costs in addition to depreciation and interest on debt. Each PSA will continue through December 31, 2022, and from year to year thereafter. Either party to the respective PSA may elect to terminate the PSA by providing the other party with no less than six months advance written notice.
EEI has a PSA with IPM, whereby IPM purchases all of the capacity and energy available from EEI’s generation fleet. With limited exceptions, the price that IPM pays for capacity is the MISO Local Resources Zone 4 clearing price. IPM pays spot market prices for the associated energy. In addition, EEI will at times purchase energy from IPM to fulfill obligations to a non-affiliated party. The PSA will continue through December 31, 2022. Either party to the PSA may elect to terminate the PSA by providing the other party with no less than six months advance written notice.
Collateral Agreement
Genco has a collateral agreement with IPM pursuant to which IPM may require Genco to provide collateral to IPM to secure obligations of IPM applicable to Genco’s assets. The initial collateral limit for Genco is $15 million and IPM can demand an additional $7.5 million for a total limit not to exceed $22.5 million. There have been no amounts provided under this agreement as of September 30, 2016.
Services Agreement
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, under a services agreement (the “Services Agreement”).
The Providers act as agents for the Recipients for the limited purpose of providing the Services set forth in the Services Agreement. Prior to the beginning of each fiscal year in which Services are to be provided pursuant to the Services Agreement, the Providers and the Recipients agree on a budget for the Services, outlining, among other items, the contemplated scope of the Services to be provided in the following fiscal year and the cost of providing the Services. The Recipients will pay the Providers an annual management fee as agreed in the budget. We believe this is a reasonable method of allocating the costs of the Services to us and provides an appropriate reflection of the costs we would have incurred if we operated as an unaffiliated entity.
Effective December 31, 2015, we amended the Services Agreement to provide that payments due in 2016 to Dynegy for services incurred may be deferred. Any deferred payments, and associated interest, will be reflected as an affiliate payable to be settled at the discretion of Dynegy or us.
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 provides that accumulated taxes payable to Dynegy, and any associated interest, be settled at the discretion of Dynegy or us.

13
ILLINOIS POWER GENERATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended September 30, 2016 and 2015

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.  Our effective tax rate of 16% is lower than the statutory rate of 35% as a result of the recognition of a valuation allowance primarily caused by the impairment of our Newton facility.
Note 12—Pension and Other Post-Employment Benefits
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.
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, 2016 and 2015. Also reflected is an allocation of net periodic benefit cost (gain) from our participation in Dynegy’s single-employer pension and other post-employment plans for the three and nine months ended September 30, 2016 and 2015.
  
 
Pension Benefits
 
Other Benefits
 
 
Three Months Ended September 30,
(amounts in millions)
 
2016
 
2015
 
2016
 
2015
Service cost
 
$
—

 
$
1

 
$
—

 
$
—

Interest cost
 
—

 
—

 
—

 
1

Expected return on plan assets
 
(1
)
 
(1
)
 
—

 
(1
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service credit
 
1

 
1

 
(1
)
 
(1
)
Net periodic benefit cost (gain)
 
$
—

 
$
1

 
$
(1
)
 
$
(1
)
  
 
Pension Benefits
 
Other Benefits
 
 
Nine Months Ended September 30,
(amounts in millions)
 
2016
 
2015
 
2016
 
2015
Service cost
 
$
2

 
$
2

 
$
—

 
$
1

Interest cost
 
2

 
2

 
1

 
2

Expected return on plan assets
 
(3
)
 
(3
)
 
(2
)
 
(3
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service credit
 
1

 
1

 
(2
)
 
(1
)
Net periodic benefit cost (gain)
 
$
2

 
$
2

 
$
(3
)
 
$
(1
)
Note 13—Subsequent Events
Genco Debt Restructure
On October 14, 2016, we entered into the RSA with Dynegy and the Ad Hoc Group to restructure our Senior Notes either through (a) the Exchange Offer of our Senior Notes or (b) if the conditions to the Exchange Offer are not satisfied or waived (as discussed below), the Plan filed in a Chapter 11 case under the Bankruptcy code. On November 7, 2016, we launched the Restructuring in accordance with the terms of the RSA. Pursuant to the Exchange Offer, the $825 million of our existing Senior Notes will be exchanged for up to (i) $210 million in new seven-year Dynegy unsecured notes, (ii) $130 million of cash consideration (subject to reductions for interest payments) funded with existing IPH cash balances and an expected return of collateral of

14
ILLINOIS POWER GENERATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended September 30, 2016 and 2015

approximately $61 million, and (iii) 10 million new Dynegy warrants with a seven-year term for an exercise price of $35 per share. In addition, the Exchange Offer includes a solicitation of consents to proposed amendments to the indenture governing our Senior Notes. The Exchange Offer period under the Restructuring will expire on December 6, 2016, unless extended by Dynegy. If the restructuring is consummated pursuant to the Plan, it is expected that participating non-accredited investors will be entitled to a cash payment in lieu of their pro rata allocation of the notes and warrants described above. Solicitation with respect to the Exchange Offer will occur simultaneously with the solicitation of the Plan. We will continue making interest payments on our Senior Notes, with payments after September 30, 2016 netted against the proposed cash consideration.
Genco, Dynegy and the Ad Hoc Group agreed that holders of our Senior Notes who entered into the RSA on or before October 21, 2016, will be paid their pro rata share of $9 million in cash upon consummation of a restructuring, with such pro rata share determined as the proportion that the amount of our Senior Notes held by each such holder bears to the aggregate amount of our Senior Notes held by all holders entitled to receive a share of the $9 million.
If holders of 97 percent or more of the aggregate principal amount of our Senior Notes participate in the Exchange Offer and the other conditions thereto are satisfied, we intend to consummate the restructuring out of court. If holders of less than 97 percent of the aggregate principal amount of our Senior Notes, but a majority in number of the holders who have voted on the Plan and who hold at least 66.7 percent in the aggregate amount of our Senior Notes vote to accept the Plan, the parties to the RSA intend to consummate the restructuring through a prepackaged Chapter 11 filing of Genco. As of October 24, 2016, the Ad Hoc Group of our bondholders represents approximately 70 percent of the $825 million of our Senior Notes.
See Note 8—Debt for further discussion regarding the Senior Notes.

15




ILLINOIS POWER GENERATING COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
For the Interim Periods Ended September 30, 2016 and 2015
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.
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. These provisions restrict the ability to move cash out of Genco without meeting certain requirements as set forth in the governing documents. Our Senior Notes are non-recourse to Dynegy.
At September 30, 2016, our liquidity consisted of $84 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 September 30, 2016, we expect daily working capital needs and capital expenditures to be sufficiently covered by our operating cash flows and cash on hand through 2016.
Effective December 31, 2015, we amended the Services Agreement to provide that payments due in 2016 to Dynegy for services incurred may be deferred. Any deferred payments, and associated interest, will be reflected as an affiliate payable to be settled at the discretion of Dynegy or us. Please read Note 10—Related Party Transactions for further discussion.
In the second quarter of 2016, as a result of continued weak energy prices, unsold capacity volumes, on-going required maintenance and environmental expenditures, as well as consideration of a $300 million debt maturity in 2018, we engaged advisors and began a strategic review.  On October 14, 2016, we entered into the RSA with Dynegy and the Ad Hoc Group to restructure our Senior Notes either through (a) the Exchange Offer of our Senior Notes or (b) if the conditions to the Exchange Offer are not satisfied or waived, the Plan filed in a Chapter 11 case under the Bankruptcy code. On November 7, 2016, we launched the Restructuring in accordance with the terms of the RSA. Pursuant to the Exchange Offer, the $825 million of our existing Senior Notes will be exchanged for up to (i) $210 million in new seven-year Dynegy unsecured notes, (ii) $130 million of cash consideration (subject to reductions for interest payments) funded with existing IPH cash balances and an expected return of collateral of approximately $61 million, and (iii) 10 million new Dynegy warrants with a seven-year term for an exercise price of $35 per share. In addition, the Exchange Offer includes a solicitation of consents to proposed amendments to the indenture governing our Senior Notes. The Exchange Offer period under the Restructuring will expire on December 6, 2016, unless extended by Dynegy. If the restructuring is consummated pursuant to the Plan, it is expected that participating non-accredited investors will be entitled to a cash payment in lieu of their pro rata allocation of the notes and warrants described above. Solicitation with respect to the Exchange Offer will occur simultaneously with the solicitation of the Plan. We will continue making interest payments on our Senior Notes,

16



with payments after September 30, 2016 netted against the proposed cash consideration. Please read Note 13—Subsequent Events for further discussion.
On September 2, 2016, in conjunction with Ameren Energy Medina Valley Cogen, LLC, IPH filed a motion with the IPCB to terminate the variance from the SO2 annual emission rate limits provided in the MPS. IPH retired Newton Unit 2 on September 15, 2016. This retirement, along with the use of dispatch management, will allow IPH to continue to comply with the MPS SO2 limits, thereby eliminating the need for the variance. As a result, the FGD systems construction project at our Newton generation facility, including our contract with Advatech, LLC (“Advatech”), was terminated. On October 27, 2016, the IPCB granted the motion to terminate the variance. On September 30, 2016, Advatech submitted a final invoice to Genco for $81 million, and subsequently recorded a mechanics’ lien with respect to a $45 million claim.  Other than demobilization costs and a final scheduled payment, which total approximately $1 million, Genco does not believe it owes any additional amounts to Advatech. Genco considers Advatech’s claim and associated lien to be remote, without merit, and intends to vigorously dispute them.
The following table presents net cash from operating, investing, and financing activities for the nine months ended September 30, 2016 and 2015:
 
 
Nine Months Ended September 30,
(amounts in millions)
 
2016
 
2015
Net cash provided by operating activities
 
$
42

 
$
45

Net cash used in investing activities
 
$
(19
)
 
$
(43
)
Net cash provided by financing activities
 
$
—

 
$
—

Operating Activities
Historical Operating Cash Flows. Cash provided by operations totaled $42 million for the nine months ended September 30, 2016. During the period, our power generation business provided cash of $39 million due to the operation of our power generation facilities, and approximately $32 million of cash provided related to changes in working capital net of general and administrative expenses, offset by $29 million in interest payments.
Cash provided by operations totaled $45 million for the nine months ended September 30, 2015. During the period, our power generation business provided cash of $67 million primarily due to the operation of our power generation facilities and approximately $15 million of cash related to changes in working capital, offset by $37 million in interest payments.
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 requirements.
Collateral Postings. We use a portion of our capital resources in the form of cash and lines of credit to satisfy counterparty collateral demands. Our collateral postings to third parties consisted of approximately $8 million of cash at both September 30, 2016 and December 31, 2015. Please read Note 2—Accounting Policies for further discussion.
On February 26, 2014, we entered into a collateral agreement, with a total limit not to exceed $22.5 million, with IPM pursuant to which we may provide collateral to IPM to secure obligations of IPM applicable to our assets. We have provided no amounts to IPM under this agreement as of September 30, 2016.
Investing Activities
Historical Investing Cash Flows. Cash used by investing totaled $19 million for the nine months ended September 30, 2016. During the period, we had capital expenditures of approximately $33 million, offset by $14 million of after-tax proceeds realized on the 2013 sale of our gas-fired facilities. Capital expenditures included capitalized interest of $14 million.
Cash used by investing totaled $43 million for the nine months ended September 30, 2015. During the period, we had capital expenditures of approximately $43 million. This amount included capitalized interest of $16 million.
Financing Activities
Historical Financing Cash Flows. During the nine months ended September 30, 2016 and 2015, 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

17



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 Covenants. 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 September 30, 2016:
 
 
Required Ratio
 
Actual Ratio
Restricted payment interest coverage ratio (1)
 
≥1.75
 
.98
Additional indebtedness interest coverage ratio (2)
 
≥2.50
 
.98
Additional indebtedness debt-to-capital ratio (2)
 
≤60%
 
258%
__________________________________________
(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 external, third-party sources are included in the definition of indebtedness and are subject to these incurrence tests.
Based on our actual debt incurrence-related ratios noted above, as of September 30, 2016, we are prohibited from incurring additional third-party indebtedness. 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.
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 September 30, 2016, 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 September 30, 2016. Please read Note 8—Debt for further discussion on indenture provisions.
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.
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
 
Ca
 
CC
Senior Unsecured
 
Ca
 
CC
On October 7, 2016, Moody’s downgraded our Senior Unsecured credit rating from Caa3 to Ca. The downgrade was prompted by an agreement in principle between Dynegy, Genco, and the Ad Hoc Group on October 3, 2016, to restructure our Senior Notes, which Moody’s viewed as a distressed exchange.
On October 19, 2016, S&P downgraded our Senior Unsecured credit rating from CCC+ to CC. The downgrade was prompted by an agreement in principle between Dynegy, Genco, and the Ad Hoc Group on October 3, 2016, to restructure our Senior Notes, which S&P viewed as a distressed exchange.

18



Disclosure of Contractual Obligations
We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities.  Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements.  These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. 
Environmental Compliance Obligations. On September 2, 2016, IPH and Ameren Energy Medina Valley Cogen, LLC filed a motion with the IPCB to terminate the variance from the SO2 annual emission rate limits provided in the MPS. IPH retired Newton Unit 2 on September 15, 2016. This retirement, along with the use of dispatch management, will allow IPH to continue to comply with the MPS SO2 limits, thereby eliminating the need for the variance. As a result, the FGD systems construction project at our Newton generation facility was terminated. On October 27, 2016, the IPCB granted the motion to terminate the variance.
Please read “Disclosure of Contractual Obligations” in our Form 10-K for further discussion.  Please read “Uncertainty of Forward-Looking Statements and Information” for additional factors that could impact our future operating results and financial condition.
RESULTS OF OPERATIONS
Overview
In this section, we discuss our results of operations for the nine months ended September 30, 2016 and 2015.  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 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.
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. With limited exceptions, the price that IPM pays for capacity is the MISO Local Resources Zone 4 clearing price. IPM pays spot market prices for the associated energy. In addition, EEI will at times purchase energy from IPM to fulfill obligations to a non-affiliated party.
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 expenditures are key factors that we seek to control and to optimize our results of operations, financial position, and liquidity.

19



Consolidated Summary Financial Information — Three Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2015
The following table provides summary financial data regarding our consolidated results of operations for the three months ended September 30, 2016 and 2015, respectively:
 
 
Three Months Ended September 30,
 
Favorable (Unfavorable) $ Change
 
Favorable (Unfavorable) % Change
(amounts in millions)
 
2016
 
2015
 
 
Revenues
 
$
147

 
$
146

 
$
1

 
1
 %
Cost of sales, excluding depreciation expense
 
(85
)
 
(88
)
 
3

 
3
 %
Gross margin
 
62

 
58

 
4

 
7
 %
Operating and maintenance expense
 
(34
)
 
(29
)
 
(5
)
 
(17
)%
Impairment and other charges
 
(69
)
 
(855
)
 
786

 
92
 %
Depreciation and amortization expense
 
(8
)
 
(25
)
 
17

 
68
 %
General and administrative expenses
 
(9
)
 
(4
)
 
(5
)
 
(125
)%
Operating loss
 
(58
)
 
(855
)
 
797

 
93
 %
Interest expense
 
(13
)
 
(10
)
 
(3
)
 
(30
)%
Other income and expense, net
 
1

 
—

 
1

 
NM

Loss before income taxes
 
(70
)
 
(865
)
 
795

 
92
 %
Income tax benefit
 
4

 
348

 
(344
)
 
(99
)%
Net loss
 
(66
)
 
(517
)
 
451

 
87
 %
Less: Net income attributable to noncontrolling interest
 
—

 
2

 
(2
)
 
(100
)%
Net loss attributable to Illinois Power Generating Company
 
$
(66
)
 
$
(519
)
 
$
453

 
87
 %
 
 
 
 
 
 
 
 
 
Million Megawatt Hours Generated (1)
 
3.7

 
3.7

 
—

 
—
 %
IMA for Genco Facilities (2)
 
88
%
 
89
%
 
 
 
 
Average Capacity Factor for Genco Facilities (3)
 
55
%
 
55
%
 
 
 
 
Average Quoted Market Power Prices ($/MWh) (4)
 
 
 
 
 
 
 
 
On-Peak: Indiana (Indy Hub)
 
$
40.19

 
$
33.09

 
$
7.10

 
21
 %
Off-Peak: Indiana (Indy Hub)
 
$
24.38

 
$
23.37

 
$
1.01

 
4
 %
 ________________________________________
(1)
Includes EEI generation at 100 percent.
(2)
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.
(3)
Reflects actual production as a percentage of available capacity.
(4)
Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
Discussion of Consolidated Results of Operations
Revenues. Revenues increased by $1 million from $146 million in 2015 to $147 million in 2016. The increase is due to $8 million in higher revenues allocated to us through the PSAs as a result of increased prices in 2016. Partially offsetting the increase is $7 million of lower reimbursed costs relating to operating and maintenance expenses, and depreciation expense. Each of these items is discussed separately below.
Cost of Sales. Cost of sales decreased by $3 million from $88 million in 2015 to $85 million in 2016. The decrease is primarily due to $10 million in lower coal and transportation expense due to decreased generation volumes as a result of milder weather and lower contracted coal prices during 2016. Partially offsetting the decrease is a $7 million increase in natural gas costs at our Joppa facility related to SO2 emission reduction efforts.


20



Operating and Maintenance Expense. Operating and maintenance expense increased by $5 million from $29 million in 2015 to $34 million in 2016. The change was primarily due to $2 million increase in plant and equipment maintenance related to an outage at our Coffeen facility, a $1 million increase in environmental charges, and a $1 million Ad Valorem tax adjustment.
General and Administrative Expenses. General and administrative expenses increased by $5 million from $4 million in 2015 to $9 million in 2016. The increase of $5 million is primarily due to an increase of $4 million in legal expenses, and an increase of $1 million in the allocation of service agreement expenses period over period.
Impairments. Impairments decreased $786 million due to a charge in 2016 of $69 million on our Newton facility, compared to a charge in 2015 of $855 million on our Coffeen facility. Please see Note 7—Property, Plant and Equipment for further discussion.
Depreciation and Amortization Expense. Depreciation and amortization expense decreased by $17 million from $25 million in 2015 to $8 million in 2016, primarily due to a reduction in our depreciable asset base as a result of the impairment of our Coffeen assets during the third quarter of 2015 and Newton assets in the second quarter of 2016.
Income Tax Benefit. Our income tax benefit decreased by $344 million from $348 million in 2015 to $4 million in 2016. The decrease in the benefit is primarily related to a lower effective tax rate that includes recognition of a valuation allowance as applied against our losses before income taxes when comparing the two periods that include the additional impairment of our Newton facility in 2016 and the impairment of our Coffeen facility in 2015.

21



Consolidated Summary Financial Information — Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015
The following table provides summary financial data regarding our consolidated results of operations for the nine months ended September 30, 2016 and 2015, respectively:
 
 
Nine Months Ended September 30,
 
Favorable (Unfavorable) $ Change
 
Favorable (Unfavorable) % Change
(amounts in millions)
 
2016
 
2015
 
 
Revenues
 
$
343

 
$
420

 
$
(77
)
 
(18
)%
Cost of sales, excluding depreciation expense
 
(212
)
 
(265
)
 
53

 
20
 %
Gross margin
 
131

 
155

 
(24
)
 
(15
)%
Operating and maintenance expense
 
(93
)
 
(104
)
 
11

 
11
 %
Impairment and other charges
 
(736
)
 
(855
)
 
119

 
14
 %
Depreciation and amortization expense
 
(27
)
 
(75
)
 
48

 
64
 %
General and administrative expenses
 
(19
)
 
(17
)
 
(2
)
 
(12
)%
Operating loss
 
(744
)
 
(896
)
 
152

 
17
 %
Interest expense
 
(32
)
 
(29
)
 
(3
)
 
(10
)%
Other income and expense, net
 
15

 
—

 
15

 
NM

Loss before income taxes
 
(761
)
 
(925
)
 
164

 
18
 %
Income tax benefit
 
118

 
373

 
(255
)
 
(68
)%
Net loss
 
(643
)
 
(552
)
 
(91
)
 
(16
)%
Less: Net loss attributable to noncontrolling interest
 
(2
)
 
(1
)
 
(1
)
 
(100
)%
Net loss attributable to Illinois Power Generating Company
 
$
(641
)
 
$
(551
)
 
$
(90
)
 
(16
)%
 
 
 
 
 
 
 
 
 
Million Megawatt Hours Generated (1)
 
8.4

 
11.4

 
(3.0
)
 
(26
)%
IMA for Genco Facilities (2)
 
89
%
 
92
%
 
 
 
 
Average Capacity Factor for Genco Facilities (3)
 
41
%
 
55
%
 
 
 
 
Average Quoted Market Power Prices ($/MWh) (4)
 
 
 
 
 
 
 
 
On-Peak: Indiana (Indy Hub)
 
$
32.32

 
$
35.17

 
$
(2.85
)
 
(8
)%
Off-Peak: Indiana (Indy Hub)
 
$
22.31

 
$
25.41

 
$
(3.10
)
 
(12
)%
 ________________________________________
(1)
Includes EEI generation at 100 percent.
(2)
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.
(3)
Reflects actual production as a percentage of available capacity.
(4)
Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
Discussion of Consolidated Results of Operations
Revenues. Revenues decreased by $77 million from $420 million in 2015 to $343 million in 2016. The decrease is due to $27 million in lower revenues allocated to us through the PSAs as a result of decreased generation volumes in 2016. Also contributing to the decrease is $49 million of lower reimbursed costs relating to operating and maintenance expense, and depreciation expense. Each of these expense items is discussed separately below.
Cost of Sales. Cost of sales decreased by $53 million from $265 million in 2015 to $212 million in 2016. The decrease is primarily due to a decrease of $78 million in coal and transportation expense due to decreased generation volumes as a result of milder weather and lower contracted coal prices during 2016. Partially offsetting the decrease is a $16 million one-time contract termination fee and a $9 million increase in natural gas costs at our Joppa facility related to SO2 emission reduction efforts.
Operating and Maintenance Expense. Operating and maintenance expense decreased by $11 million from $104 million in 2015 to $93 million in 2016. The change was primarily due to reduced outages resulting in a decrease of $4 million in plant

22



and equipment maintenance, a $3 million decrease in accretion expenses related to our EEI and Newton facilities, a $3 million decrease in operating material purchases, and a $1 million decrease related to capital removal cost at our Newton facility.
General and Administrative Expenses. General and administrative expenses increased by $2 million from $17 million in 2015 to $19 million in 2016. The increase of $2 million is primarily due to an increase of $5 million in legal expenses, partially offset by a decrease of $3 million in the allocation of service agreement expenses period over period.
Impairments. Impairments decreased $119 million due to charges in 2016 of $736 million on our Newton facility, compared to a charge in 2015 of $855 million on our Coffeen facility. Please see Note 7—Property, Plant and Equipment for further discussion.
Depreciation and Amortization Expense. Depreciation and amortization expense decreased by $48 million from $75 million in 2015 to $27 million in 2016, primarily due to a reduction in our depreciable asset base as a result of the impairment of our Coffeen assets during the third quarter of 2015 and Newton assets in the second quarter of 2016.
Other Income and Expense. Other income increased by $15 million when compared to the same period prior year, primarily due to $14 million in previously contingent proceeds received from our previous owner, Ameren, related to the 2013 sale of our gas-fired facilities.
Income Tax Benefit. Our income tax benefit decreased by $255 million, from $373 million in 2015 to $118 million in 2016. The decrease in the benefit is primarily related to a lower effective tax rate that includes recognition of a valuation allowance as applied against our losses before income taxes when comparing the two periods that include the impairment of our Newton facility in 2016 and the impairment of our Coffeen facility in 2015.
Outlook
As a result of continued weak energy prices, unsold capacity volumes, on-going required maintenance and environmental expenditures, as well as consideration of a $300 million debt maturity in 2018, we engaged advisors and began a strategic review.  On October 14, 2016, we entered into the RSA with Dynegy and the Ad Hoc Group to restructure our Senior Notes either through (a) the Exchange Offer of our Senior Notes or (b) if the conditions to the Exchange Offer are not satisfied or waived, the Plan filed in a Chapter 11 case under the Bankruptcy code. On November 7, 2016, we launched the Restructuring in accordance with the terms of the RSA. Please read Note 13—Subsequent Events for further discussion.
Genco is comprised of three power generation facilities totaling 2,553 MW located within the state of Illinois. Coffeen and Newton primarily operate in MISO. Joppa, which is within the EEI control area, is interconnected to Tennessee Valley Authority and Louisville Gas and Electric Company, but through IPM primarily sells its capacity and energy to MISO.
Through IPM, we sell our capacity through five main channels to market: bilateral sales, wholesale transactions, retail sales, PJM exports, and the MISO capacity auction. The MISO capacity auction is typically our final opportunity to market the remaining capacity in MISO. 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. For Planning Year 2016-2017, Local Resource Zone 4 cleared at $72 per MW-day with no volumes sold incremental to our load obligations.
A majority of the Mercury and Air Toxic Standards related asset retirements will conclude this year; however, we expect economic retirements to continue reducing reserve margins in MISO. MISO has a Planning Reserve Margin of 15.8 percent and has forecasted reserve margins of 15.8 percent for Planning Year 2017-2018, 15.6 percent for Planning Year 2018-2019, 15.3 percent for Planning Year 2019-2020, 15.4 percent for Planning Year 2020-2021, and 15.5 percent for Planning Year 2021-2022.
Through IPM, we also sell a portion of our capacity into the PJM control area. Genco will pseudo-tie an additional 240 MW into PJM from our Joppa facility beginning June 1, 2017.  As of June 1, 2017, Genco will have 698 MW, or 27 percent of its current capacity and energy, electrically tied into PJM through pseudo-tie arrangements. As of June 1, 2016, our Coffeen and Newton facilities have 458 MW, or 18 percent of our current capacity and energy, that is electrically tied to and becomes baseload generation for PJM through pseudo-tie arrangements. PJM’s capacity market construct is more favorable than MISO’s due to (i) a three-year forward auction versus a prompt year auction in MISO, (ii) a sloped demand curve versus the vertical demand curve in MISO, and (iii) minimum offer price rule in PJM versus vertically integrated utilities offering in at a zero price in MISO.
PJM has begun the transition of the PJM capacity market to the Capacity Performance (“CP”) product. On August 26-27, 2015, PJM held a transitional 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 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 Base Residual Auction (“BRA”)

23



to procure CP for 80 percent and Base Capacity (“Base”) for 20 percent of PJM’s capacity needs for Planning Year 2018-2019 and Planning Year 2019-2020. PJM will procure 100 percent CP beginning with Planning Year 2020-2021.
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 at $165 per MW-day. For Planning Year 2019-2020 BRA, we cleared 384 MW (164 MW Base and 220 MW CP).
As of September 15, 2016, the 615 MW Unit 2 at the Newton power generation facility in Newton, Illinois has been retired. This decision was made after Newton failed to recover its basic operating costs in the most recent MISO auction, in addition to a low power pricing environment and significant maintenance and environmental expenditures required to appropriately maintain the facility.
As of October 12, 2016, our expected remaining 2016 coal requirements are fully contracted and 79 percent priced. Our forecasted coal requirements for 2017 are 87 percent contracted and 62 percent priced. We look to procure and price additional fuel opportunistically. Our coal transportation requirements are fully contracted for 2016 and 2017. Our coal transportation requirements are approximately 79 percent contracted for 2018 to 2020. During 2015, we entered into a long-term transportation agreement for the Joppa facility which will begin in 2018 and is also a reduction from the 2017 rate.
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. Dynegy complied fully with the terms of the MISO tariff in connection with the 2015-2016 PRA.  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 proposals made by complainants. The technical conference did not address the ongoing Office of Enforcement investigation.
On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions associated with calculating Initial Reference Levels and Local Clearing Requirements, effective as of the 2016-2017 PRA. Under the order, FERC found that the existing tariff provision, which bases Initial Reference Levels for capacity supply offers on the estimated opportunity cost of exporting capacity to a neighboring region (for example, PJM), is no longer just and reasonable. Accordingly, FERC required MISO to set the Initial Reference Level for capacity at $0 per MW-day for the 2016-2017 PRA. Capacity suppliers may also request a facility-specific reference level from the MISO IMM. The order did not address the other arguments of the complainants regarding the 2015-2016 Auction, and stated that those issues remain under consideration and will be addressed in a future order.
On November 1, 2016 MISO filed their proposal with FERC in Docket No. ER17-284-000 to establish a Forward Resource Auction (FRA) in order to assure long-term resource adequacy for the competitive retail demand areas of their market - primarily Zones 4 and 7.  Similar to PJM and ISO-NE, MISO has proposed a separate three-year FRA that will include downward sloping demand curve or variable reliability target. MISO requested an effective date of March 1, 2017 and the FRA implementation would begin with a series of four interim auctions commencing in March 2018 for the 2018-2019 Planning Year with catch-up forward auctions for Planning Years 2019-2020, 2020-2021, and 2021-2022 beginning in August 2018.

24



Environmental and Regulatory Matters
Please read Item 1. Business—Environmental Matters in our Form 10-K and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Outlook—Environmental and Regulatory Matters in our Form 10-Q for the periods ended March 31 and June 30, 2016 for a detailed discussion of our environmental and regulatory matters.
Multi-Pollutant Air Emission Initiatives
IPH Variance. On September 2, 2016, IPH and Ameren Energy Medina Valley Cogen, LLC filed a motion with the IPCB to terminate the variance from the SO2 annual emission rate limits provided in the MPS. IPH has complied with all conditions of the variance, including retirement of Edwards Unit 1 on January 1, 2016. In addition, IPH has operated in compliance with the MPS SO2 limit during 2016. IPH retired Newton Unit 2 on September 15, 2016. This retirement, along with the use of dispatch management, will allow IPH to continue to comply with the SO2 limits in the MPS, thereby eliminating the need for the variance. As a result, the FGD systems construction project at our Newton generation facility was terminated. On October 27, 2016, the IPCB granted the motion to terminate the variance.    
The Clean Water Act
Effluent Limitation Guidelines (“ELG”). We have evaluated the ELG final rule and at this time, we estimate the cost of our compliance with the ELG rule to be approximately $55 million to $66 million. The majority of ELG compliance expenditures are expected to occur in the 2016-2023 timeframe. As planning and work progress, we continue to review our estimates as well as timing of our capital expenditures. The following table presents the projected capital expenditures by period for ELG compliance as of September 30, 2016:
(amounts in millions)
 
Less than
1 Year
 
1 - 3 Years
 
3 - 5 Years
 
More than
5 Years
 
Total
Newton
 
$
—

 
$
15

 
$
2

 
$
—

 
$
17

Coffeen
 
—

 
23

 
2

 
—

 
25

EEI
 
—

 
14

 
4

 
—

 
18

Total ELGs
 
$
—

 
$
52

 
$
8

 
$
—

 
$
60

The Clean Air Act    
CSAPR. In September 2016, the EPA issued its Cross-State Air Pollution Rule (“CSAPR”) update rule. In general, the rule lowers CSAPR’s overall NOx ozone season emissions budget beginning in 2017 to reflect the 2008 ozone National Ambient Air Quality Standards (“NAAQS”). Based on current projections for 2017, our facilities will be allocated sufficient ozone season CSAPR NOx allowances.
Coal Combustion Residuals
EPA CCR Rule. At this time, we estimate the cost of our compliance with the CCR rule will be approximately $62 million to $76 million with the majority of the expenditures in the 2016-2023 timeframe. This estimate is reflected in our asset retirement obligations (“AROs”).
Asset Retirement Obligations
AROs are recorded as liabilities on our unaudited consolidated balance sheets at their Net Present Value (“NPV”) using interest rates ranging from 10 percent to 19.4 percent. The following table presents the NPV and projected obligation as of September 30, 2016:
    
 
 
 
 
Projected Obligation by Period
(amounts in millions)
 
NPV
 
Less than
1 Year
 
1 - 3 Years
 
3 - 5 Years
 
More than
5 Years
 
Total
CCR
 
$
41

 
$
—

 
$
3

 
$
28

 
$
38

 
$
69

Non-CCR
 
9

 
1

 
2

 
9

 
79

 
91

Total AROs
 
$
50

 
$
1

 
$
5

 
$
37

 
$
117

 
$
160

    

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At September 30, 2016, Genco CCR AROs consisted of projected expenditures of $69 million related to surface impoundments and groundwater monitoring. Non-CCR AROs consisted of projected expenditures of $55 million related to asbestos removal, $28 million related to surface impoundments and groundwater monitoring, and $8 million related to landfill closures.
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 power 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;
•
beliefs associated with impairments of our long-lived assets;
•
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;
•
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, including managing risk associated with CP 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;
•
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 and our ability to meet future obligations;
•
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;
•
beliefs concerning the restructuring of our long-term debt, including the RSA, the Restructuring, the Exchange Offer and the Plan; 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.

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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 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, 2015 for detailed disclosures about market risk. There have been no changes in our market risk exposures and how those exposures are managed during the nine months ended September 30, 2016.
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 September 30, 2016.
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 September 30, 2016.

27



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 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
 
Restructuring Support Agreement dated October 14, 2016 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 14, 2016 File No. 001-33443).
10.2
 
Amendment to Restructuring Support Agreement dated October 21, 2016 (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Dynegy Inc. for the Quarter Ended September 30, 2016 File No. 001-33443).
**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.

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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:
November 10, 2016
By:
/s/ CLINT C. FREELAND
 
 
 
Clint C. Freeland
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)





29

Illinois Power Generating Co Reports