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EX-10.4 - FORM OF STOCK UNIT AWARD AGREEMENT (EVP) - DYNEGY INC.dyn-2017331xex104.htm
EX-95.1 - MINE SAFETY DISCLOSURE - DYNEGY INC.dyn-2017331_10qxex951.htm
EX-32.2 - CHIEF FINANCIAL OFFICER 906 CERTIFICATION - DYNEGY INC.dyn-2017331xex322.htm
EX-32.1 - CHIEF EXECUTIVE OFFICER 906 CERTIFICATION - DYNEGY INC.dyn-2017331xex321.htm
EX-31.2 - CHIEF FINANCIAL OFFICER 302 CERTIFICATION - DYNEGY INC.dyn-2017331xex312.htm
EX-31.1 - CHIEF EXECUTIVE OFFICER 302 CERTIFICATION - DYNEGY INC.dyn-2017331xex311.htm
EX-10.9 - SECOND AMENDMENT AGREEMENT - DYNEGY INC.dyn-2017331xex109.htm
EX-10.8 - AMENDMENT AGREEMENT - DYNEGY INC.dyn-2017331xex108.htm
EX-10.7 - AMENDMENT AND WAIVER AGREEMENT - DYNEGY INC.dyn-2017331xex107.htm
EX-10.6 - FORM OF NON-QUALIFIED STOCK OPTION AWARD AGREEMENT (EXECUTIVE) - DYNEGY INC.dyn-2017331xex106.htm
EX-10.5 - FORM OF NON-QUALIFIED STOCK OPTION AWARD AGREEMENT (CEO) - DYNEGY INC.dyn-2017331xex105.htm
EX-10.3 - FORM OF STOCK UNIT AWARD AGREEMENT (CEO) - DYNEGY INC.dyn-2017331xex103.htm
EX-10.2 - FORM OF PERFORMANCE AWARD AGREEMENT (EVP) - DYNEGY INC.dyn-2017331xex102.htm
EX-10.1 - FORM OF PERFORMANCE AWARD AGREEMENT (CEO) - DYNEGY INC.dyn-2017331xex101.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
  
FORM 10-Q
 
ý      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended March 31, 2017
 
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: 001-33443
 
DYNEGY INC.
(Exact name of registrant as specified in its charter)
State of
Incorporation
 
I.R.S. Employer
Identification No.
Delaware
 
20-5653152
 
 
 
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 x No ¨

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, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer ý
 
Accelerated filer o
Non-accelerated filer o
 
Smaller reporting company o
(Do not check if a smaller reporting company)
 
Emerging growth company o
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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




Indicate by check mark whether the registrant filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes x No ¨

Indicate the number of shares outstanding of our class of common stock, as of the latest practicable date: Common stock, $0.01 par value per share, 131,345,529 shares outstanding as of April 12, 2017.
 



TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
Item 1.
 
 
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
 
 
 
 
Item 1.
Item 1A.
Item 4.

Item 6.
 
 
 



DEFINITIONS
As used in this Form 10-Q, the abbreviations contained herein have the meanings set forth below. 
ATSI
 
American Transmission Service, Inc.
CAA
 
Clean Air Act
CAISO
 
The California Independent System Operator
CDD
 
Cooling Degree Days
COMED
 
Commonwealth Edison
CPUC
 
California Public Utility Commission
CT
 
Combustion Turbine
EBITDA
 
Earnings Before Interest, Taxes, Depreciation and Amortization
EMAAC
 
Eastern Mid-Atlantic Area Council
EPA
 
Environmental Protection Agency
ERCOT
 
Electric Reliability Council of Texas
FCA
 
Forward Capacity Auction
FERC
 
Federal Energy Regulatory Commission
FTR
 
Financial Transmission Rights
HDD
 
Heating Degree Days
IMA
 
In-market Asset Availability
IPCB
 
Illinois Pollution Control Board
IPH
 
IPH, LLC (formerly known as Illinois Power Holdings, LLC)
ISO
 
Independent System Operator
ISO-NE
 
Independent System Operator New England
kW
 
Kilowatt
LIBOR
 
London Interbank Offered Rate
MAAC
 
Mid-Atlantic Area Council
MISO
 
Midcontinent Independent System Operator, Inc.
MMBtu
 
One Million British Thermal Units
Moody’s
 
Moody’s Investors Service Inc.
MW
 
Megawatts
MWh
 
Megawatt Hour
NYISO
 
New York Independent System Operator
PJM
 
PJM Interconnection, LLC
PPL
 
PPL Electric Utilities, Corp.
PRIDE
 
Producing Results through Innovation by Dynegy Employees
RGGI
 
Regional Greenhouse Gas Initiative
RTO
 
Regional Transmission Organization

S&P
 
Standard & Poor’s Ratings Services
SEC
 
U.S. Securities and Exchange Commission

i


PART I. FINANCIAL INFORMATION
Item 1—FINANCIAL STATEMENTS
DYNEGY INC.
CONSOLIDATED BALANCE SHEETS
(unaudited) (in millions, except share data)
 
 
 
March 31, 2017
 
December 31, 2016
ASSETS
 
 

 
 

Current Assets
 
 

 
 

Cash and cash equivalents
 
$
467

 
$
1,776

Restricted cash
 

 
62

Accounts receivable, net of allowance for doubtful accounts of $1 and $1, respectively
 
394

 
386

Inventory
 
513

 
445

Assets from risk management activities
 
129

 
130

Intangible assets
 
31

 
38

Prepayments and other current assets
 
157

 
150

Total Current Assets
 
1,691

 
2,987

Property, plant and equipment, net
 
9,719

 
7,121

Investment in unconsolidated affiliate
 
149

 

Restricted cash
 

 
2,000

Assets from risk management activities
 
34

 
16

Goodwill
 
799

 
799

Intangible assets
 
63

 
23

Assets held-for-sale
 
451

 

Other long-term assets
 
174

 
107

Total Assets
 
$
13,080

 
$
13,053

 
See the notes to consolidated financial statements.

1



DYNEGY INC.
CONSOLIDATED BALANCE SHEETS
(unaudited) (in millions, except share data)

 
 
 
March 31, 2017
 
December 31, 2016
LIABILITIES AND EQUITY
 
 

 
 

Current Liabilities
 
 

 
 

Accounts payable
 
$
287

 
$
332

Accrued interest
 
205

 
81

Intangible liabilities
 
34

 
21

Accrued liabilities and other current liabilities
 
137

 
133

Liabilities from risk management activities
 
66

 
97

Asset retirement obligations
 
58

 
51

Debt, current portion, net
 
117

 
201

Total Current Liabilities
 
904

 
916

Liabilities subject to compromise (Note 18)
 

 
832

Debt, long-term portion, net
 
9,200

 
8,778

Liabilities from risk management activities
 
50

 
43

Asset retirement obligations
 
259

 
236

Deferred income taxes
 
35

 
5

Intangible liabilities
 
45

 
34

Other long-term liabilities
 
165

 
170

Total Liabilities
 
10,658

 
11,014

Commitments and Contingencies (Note 13)
 


 


 
 
 
 
 
Stockholders’ Equity
 
 
 
 
Preferred stock, $0.01 par value, 20,000,000 shares authorized:
 
 
 
 
Series A 5.375% mandatory convertible preferred stock, $0.01 par value; 4,000,000 shares issued and outstanding, respectively
 
400

 
400

Common stock, $0.01 par value, 420,000,000 shares authorized; 142,645,810 shares issued and 131,319,688 shares outstanding at March 31, 2017; 128,626,740 shares issued and 117,300,618 outstanding at December 31, 2016
 
1

 
1

Additional paid-in capital
 
3,321

 
3,547

Accumulated other comprehensive income, net of tax
 
34

 
21

Accumulated deficit
 
(1,330
)
 
(1,927
)
Total Dynegy Stockholders’ Equity
 
2,426

 
2,042

Noncontrolling interest
 
(4
)
 
(3
)
Total Equity
 
2,422

 
2,039

Total Liabilities and Equity
 
$
13,080

 
$
13,053


See the notes to consolidated financial statements.

2


DYNEGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited) (in millions, except per share data)

 
 
Three Months Ended March 31,
 
 
2017
 
2016
Revenues
 
$
1,247

 
$
1,123

Cost of sales, excluding depreciation expense
 
(757
)
 
(545
)
Gross margin
 
490

 
578

Operating and maintenance expense
 
(232
)
 
(221
)
Depreciation expense
 
(200
)
 
(171
)
Impairments
 
(20
)
 

General and administrative expense
 
(40
)
 
(37
)
Acquisition and integration costs
 
(45
)
 
(4
)
Other
 
(2
)
 

Operating income (loss)
 
(49
)
 
145

Bankruptcy reorganization items (Note 18)
 
483

 

Earnings (losses) from unconsolidated investments
 
(1
)
 
2

Interest expense
 
(167
)
 
(142
)
Other income and expense, net
 
17

 
1

Income before income taxes
 
283

 
6

Income tax benefit (expense) (Note 14)
 
313

 
(16
)
Net income (loss)
 
596

 
(10
)
Less: Net loss attributable to noncontrolling interest
 
(1
)
 

Net income (loss) attributable to Dynegy Inc.
 
597

 
(10
)
Less: Dividends on preferred stock
 
5

 
5

Net income (loss) attributable to Dynegy Inc. common stockholders
 
$
592

 
$
(15
)
 
 
 
 
 
Earnings (Loss) Per Share (Note 16):
 
 
 
 
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders
 
$
4.00

 
$
(0.13
)
Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders
 
$
3.57

 
$
(0.13
)
 
 
 
 
 
Basic shares outstanding
 
148

 
117

Diluted shares outstanding
 
167

 
117

 
See the notes to consolidated financial statements.

3


DYNEGY INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(unaudited) (in millions)

 
 
Three Months Ended March 31,
 
 
2017
 
2016
Net income (loss)
 
$
596

 
$
(10
)
Other comprehensive income (loss) before reclassifications:
 
 
 
 
Actuarial gain and plan amendment (net of tax of zero and zero, respectively)
 
15

 

Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
Amortization of unrecognized prior service credit (net of tax of zero and zero, respectively)
 
(2
)
 
(1
)
Other comprehensive income (loss), net of tax
 
13

 
(1
)
Comprehensive income (loss)
 
609

 
(11
)
Less: Comprehensive loss attributable to noncontrolling interest
 
(1
)
 

Total comprehensive income (loss) attributable to Dynegy Inc.
 
$
610

 
$
(11
)

See the notes to consolidated financial statements.

4


DYNEGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited) (in millions)
 
 
Three Months Ended March 31,
 
 
2017
 
2016
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 

 
 

Net income (loss)
 
$
596

 
$
(10
)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
 
 
 
 
Depreciation expense
 
200

 
171

Non-cash interest expense
 
20

 
10

Amortization of intangibles
 
11

 
14

Risk management activities
 
(20
)
 
(109
)
(Earnings) loss from unconsolidated investments
 
1

 
(2
)
Deferred income taxes
 
(313
)
 
16

Impairments
 
20

 

Change in value of common stock warrants
 
(12
)
 
(1
)
Bankruptcy reorganization items
 
(483
)
 

Other
 
16

 
13

Changes in working capital:
 
 
 
 
Accounts receivable, net
 
24

 
65

Inventory
 
33

 
18

Prepayments and other current assets
 
19

 
28

Accounts payable and accrued liabilities
 
38

 
43

Changes in non-current assets
 

 
(10
)
Changes in non-current liabilities
 
(1
)
 
3

Net cash provided by operating activities
 
149

 
249

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 

 
 

Capital expenditures
 
(31
)
 
(125
)
Acquisitions, net of cash acquired
 
(3,263
)
 

Distributions from unconsolidated investments
 
2

 
8

Net cash used in investing activities
 
(3,292
)
 
(117
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 

 
 

Proceeds from long-term borrowings, net of debt issuance costs
 
425

 
198

Repayments of borrowings
 
(299
)
 
(5
)
Proceeds from issuance of equity, net of issuance costs
 
150

 

Preferred stock dividends paid
 
(5
)
 
(5
)
Interest rate swap settlement payments
 
(4
)
 
(4
)
Acquisition of noncontrolling interest
 
(375
)
 

Payments related to bankruptcy financing

 
(119
)
 

Other financing
 
(1
)
 
(2
)
Net cash provided by (used in) financing activities
 
(228
)
 
182

Net increase (decrease) in cash, cash equivalents and restricted cash
 
(3,371
)
 
314

Cash, cash equivalents and restricted cash, beginning of period
 
3,838

 
544

Cash, cash equivalents and restricted cash, end of period
 
$
467

 
$
858

 

See the notes to consolidated financial statements. 

5

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016


Note 1—Basis of Presentation and Organization
The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. The year-end consolidated balance sheet data was derived from audited consolidated financial statements, but does not include all disclosures required by the 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 unaudited 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, 2016, filed with the SEC on February 24, 2017, which we refer to as our “Form 10-K.” Unless the context indicates otherwise, throughout this report, the terms “Dynegy,” “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Dynegy Inc. and its direct and indirect subsidiaries.
We sell electric energy, capacity and ancillary services primarily on a wholesale basis from our power generation facilities. We also serve residential, municipal, commercial and industrial customers primarily in MISO and PJM through our Homefield Energy and Dynegy Energy Services retail businesses. We report the results of our power generation business as six segments in our unaudited consolidated financial statements: (i) PJM, (ii) ISO-NE/NYISO (“NY/NE”), (iii) ERCOT, (iv) MISO, (v) IPH, and (vi) CAISO. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense, and income tax benefit (expense). All significant intercompany transactions have been eliminated. Please read Note 19—Segment Information for further discussion.
On February 2, 2017 (the “Emergence Date”), Illinois Power Generating Company (“Genco”) emerged from bankruptcy. Please read Note 18—Genco Chapter 11 Bankruptcy and Emergence for further discussion.
Note 2—Accounting Policies
The accounting policies followed by the Company are set forth in Note 2—Summary of Significant Accounting Policies in our Form 10-K. The accompanying unaudited consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries. Accounting policies for all of our operations are in accordance with GAAP. Except for the adoption of new policies as described below, there have been no significant changes to our accounting policies during the three months ended March 31, 2017.
Use of Estimates. The preparation of unaudited consolidated financial statements in conformity with GAAP requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information.  Actual results could differ materially from our estimates. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures, and other factors.
Accounting Standards Adopted
Statement of Cash Flows. In August 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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. We adopted this ASU on January 1, 2017 and applied the amendments on a retrospective basis. The adoption of this ASU affected the classification of prepayments for future planned outage work performed under long-term service agreements. The majority of the cash prepayments required under these agreements will now be reflected as cash outflows from investing activities and the remainder will be classified as cash outflows from operating activities, based on whether they are anticipated to be expensed or capitalized. As a result of the retrospective application of this ASU, we reclassified approximately $60 million of cash prepayments from operating activities to investing activities in our unaudited consolidated statement of cash flows for the three months ended March 31, 2016.
In November 2016, the FASB issued ASU 2016-18-Statement of Cash Flows (Topic 230): Restricted Cash. The amendments in this ASU require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally

6

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. We adopted this ASU as of January 1, 2017 and applied the amendments on a retrospective basis. As a result of the retrospective application of this ASU, changes in restricted cash of $2 million previously reflected as cash flows from operating activities is now reflected in Net increase (decrease) in cash, cash equivalents, and restricted cash in our unaudited consolidated statement of cash flows for the three months ended March 31, 2016. Additionally, restricted cash of $39 million and $37 million are now reflected in the beginning of period and end of period cash, cash equivalents and restricted cash line items, respectively, of the statement of cash flow for the three months ended March 31, 2016. Please read Note 7—Cash Flow Information for further discussion.
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. We adopted this ASU on January 1, 2017 with no material impact on our unaudited consolidated financial statements.
Goodwill. In January 2017, the FASB issued ASU 2017-04-Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. To simplify the subsequent measure of goodwill, the amendments in this ASU eliminate step two from the goodwill impairment test. An entity will no longer be required to calculate the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination to determine the impairment of goodwill. The amendments in this ASU will now require goodwill impairment to be measured by the amount by which the carrying value of the reporting unit exceeds its fair value. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Upon adoption, an entity shall apply the guidance in this ASU prospectively with early adoption permitted for annual goodwill tests performed after January 1, 2017. We adopted this ASU on January 1, 2017 with no material impact on our unaudited consolidated financial statements.
Accounting Standards Not Yet Adopted
Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The amendments in this ASU will mainly require lessees to recognize lease assets and lease liabilities, for those leases classified as operating leases under GAAP, in their balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, 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 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 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 are 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 have established an implementation team to assess the impact the new accounting standard will have on our financial statements upon adoption and have not identified a material change to the timing of our revenue recognition. Additionally, our implementation team is currently assessing the impact of the standard by reviewing revenue earned from contracts to determine if changes in our policies and controls are necessary. The implementation team has identified that we will need to expand our footnote disclosures to include a presentation of the source of our revenue. We believe this disclosure will include a regional presentation of our revenues, similar to our presentation of revenues by segment, disaggregated by revenue type - power sales, capacity sales, and ancillary services. We anticipate using the modified retrospective method, and, while our evaluation of the new accounting standard is still ongoing, we have not yet identified any significant changes to our existing policies and controls.

7

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Note 3—Acquisitions and Divestitures
Acquisition
ENGIE Acquisition. On February 7, 2017 (the “ENGIE Acquisition Closing Date”), pursuant to the terms of the stock purchase agreement, as amended and restated on June 27, 2016, (the “ENGIE Acquisition Stock Purchase Agreement”), Dynegy acquired approximately 9,017 MW of generation from GDF SUEZ Energy North America, Inc. (“GSENA”) and International Power, S.A. (the “Seller”), including (i) 15 natural gas-fired facilities located in Illinois, Massachusetts, New Jersey, Ohio, Pennsylvania, Texas, Virginia, and West Virginia, (ii) one coal-fired facility in Texas, and (iii) one waste coal-fired facility in Pennsylvania for a base purchase price of approximately $3.3 billion in cash, subject to certain adjustments (the “ENGIE Acquisition”). On February 2, 2017, FERC issued an order accepting the December 27, 2016 Compliance Filing of Atlas Power Finance, LLC, Dynegy, and ECP (collectively, “Applicants”), which proposed mitigation measures in response to market power concerns identified by FERC in its December 22, 2016 order conditionally authorizing the ENGIE Acquisition. In this order, FERC accepted, among other commitments, Applicants’ proposal to divest at least 224 MW in the Southeast New England capacity zone in ISO-NE, and Applicants’ commitment to execute agreements to sell such capacity by August 7, 2017.
Stock Purchase Agreement-Terawatt and ECP Buyout. On February 24, 2016, Dynegy entered into a Stock Purchase Agreement with Terawatt Holdings, LP (“Terawatt”), an affiliate of the ECP Funds (the “PIPE Stock Purchase Agreement”), pursuant to which at the ENGIE Acquisition Closing Date, Dynegy issued to Terawatt 13,711,152 shares (the “PIPE Shares”) of Dynegy common stock for $150 million (the “PIPE Transaction”). In connection with the closing of the PIPE Transaction, Dynegy and Terawatt entered into an Investor Rights Agreement, (the “Investor Rights Agreement”). Under the Investor Rights Agreement, Terawatt is entitled to certain rights, including certain registration rights, rights of first refusal with respect to certain issuances of our equity and the designation of one individual to serve on our Board of Directors as long as Terawatt and its affiliates own at least 10 percent of our common stock. Further, the Investor Rights Agreement subjects Terawatt to certain obligations, including certain voting obligations and customary standstill and lock-up periods. Separately, Dynegy settled its payment obligation to Energy Capital Partners (“ECP”) of $375 million (the “ECP Buyout Price”). This payment is recorded as a reduction in additional paid-in capital in our unaudited consolidated balance sheet and is reflected as a purchase of a noncontrolling interest in financing activities in our unaudited consolidated statement of cash flows.
Business Combination Accounting. The ENGIE Acquisition has been accounted for in accordance with Accounting Standards Codification (“ASC”) 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date, February 7, 2017. A summary of the various techniques used to fair value the identifiable assets and liabilities, as well as their classification within the fair value hierarchy are listed below.
Working capital was valued using available market information (Level 2).
Acquired property, plant and equipment (“PP&E”), excluding those assets classified as held-for-sale, was valued using a discounted cash flow (“DCF”) analysis based upon a debt-free, free cash flow model (Level 3). The DCF model was created for each power generation facility based on its remaining useful life, and:
for the years 2017 and 2018, included gross margin forecasts using quoted forward commodity market prices;
for the years 2019 through 2026, we used gross margin forecasts based upon commodity and capacity price curves developed internally using forward New York Mercantile Exchange natural gas prices and supply and demand factors;
for periods beyond 2026, we assumed a 2.5 percent growth rate.
We also used management’s forecasts of operations and maintenance expense, general and administrative expense, as well as capital expenditures for the years 2017 through 2021, and for years thereafter assumed a 2.5 percent growth rate. These cash flows were discounted using discount rates of approximately 9 percent to 13 percent for gas-fired, and approximately 13 percent to 14 percent for coal-fired, generation facilities, based upon the plant’s age, efficiency, region, and years until retirement.
Acquired PP&E classified as held-for-sale was valued based upon the sale price of the assets (Level 2).
Acquired derivatives were valued using the methods described in Note 6—Fair Value Measurements (Level 2 or Level 3).
Contracts with terms that were not at current market prices were also valued using a DCF analysis (Level 3).  The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference recorded as either an intangible asset or liability.

8

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Asset retirement obligations (“AROs”) were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations (Level 3).
The following table summarizes the consideration paid and the provisional fair value amounts recognized for the assets acquired and liabilities assumed related to the ENGIE Acquisition, as of the acquisition date, February 7, 2017:
 (amounts in millions)
 
 
Base purchase price
 
$
3,300

Working capital adjustments and other (1)
 
(32
)
Fair value of total consideration transferred
 
$
3,268

 
 
 
Cash
 
$
20

Accounts receivable
 
22

Inventory
 
101

Prepayments and other current assets
 
3

Assets from risk management activities (including current portion of $21 million)
 
25

Property, plant and equipment
 
2,751

Investment in unconsolidated affiliate
 
152

Intangible assets (including current portion of $7 million)
 
50

Assets held-for-sale
 
445

Other long-term assets
 
131

Total assets acquired
 
3,700

 
 
 
Accounts payable
 
24

Liabilities from risk management activities (including current portion of $13 million)
 
16

Asset retirement obligations
 
19

Intangible liabilities (including current portion of $16 million)
 
30

Deferred income taxes, net
 
342

Other long-term liabilities
 
1

Total liabilities assumed
 
432

Net assets acquired
 
$
3,268

__________________________________________
(1)
Includes a non-cash working capital adjustment of $15 million.
The following table summarizes certain information related to the ENGIE Acquisition, which is included in our unaudited consolidated statements of operations:
 
 
Three Months Ended March 31,
(amounts in millions)
 
2017
 
2016
Acquisition costs
 
$
31

 
$
2

Revenues
 
$
78

 
N/A

Operating loss
 
$
(17
)
 
N/A


9

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Pro Forma Results. The unaudited pro forma financial results for the three months ended March 31, 2017 and 2016 assume the ENGIE Acquisition occurred on January 1, 2016. The unaudited pro forma financial results may not be indicative of the results that would have occurred had the acquisition been completed as of January 1, 2016, nor are they indicative of future results of operations.
 
 
Three Months Ended March 31,
(amounts in millions)
 
2017
 
2016
Revenue
 
$
1,303

 
$
1,286

Net income (loss)
 
$
562

 
$
(33
)
Net income (loss) attributable to Dynegy Inc.
 
$
563

 
$
(33
)
Divestitures
On February 23, 2017, Dynegy reached an agreement with LS Power for the sale of two peaking facilities in PJM for $480 million in cash. The assets to be sold, which were recently acquired in the ENGIE Acquisition, include the Armstrong and Troy facilities totaling 1,269 MW. The sale is expected to close in the second half of 2017 with the proceeds to be allocated to debt reduction.
As a result, we classified the Armstrong and Troy facilities as long-term assets held-for-sale. A detail of assets held-for-sale as of March 31, 2017 is presented below, in millions:
Inventory
 
$
11

Property, plant & equipment
 
440

Assets held-for-sale
 
$
451

Note 4—Unconsolidated Investments
Equity Method Investments
NELP. In connection with the ENGIE Acquisition, we acquired a 50 percent interest in Northeast Energy, LP (“NELP”), a joint venture with NextEra Energy, Inc., which indirectly owns the Bellingham NEA facility and the Sayreville facility. At March 31, 2017, our equity method investment in NELP included in our unaudited consolidated balance sheets was $149 million. Upon the acquisition of our NELP investment, we recognized basis differences in the net assets of approximately $14 million related to PP&E. These basis differences are being amortized over their respective useful lives. Our risk of loss related to our equity method investment is limited to our investment balance.
For the three months ended March 31, 2017, we recorded $1 million in equity losses related to our investment in NELP, which is reflected in Earnings from unconsolidated investments in our unaudited consolidated statements of operations. For the three months ended March 31, 2017, we received a distribution of $2 million, all of which was considered to be a return of investment using the cumulative earnings approach and reflected as Distributions from unconsolidated investments in our unaudited consolidated statements of cash flows.
Elwood. On November 21, 2016, Dynegy sold its 50 percent equity interest in Elwood Energy, LLC, a limited liability company (“Elwood Energy”) and Elwood Expansion LLC, a limited liability company (and together with Elwood Energy “Elwood”), to J-Power USA Development Co. Ltd. for approximately $173 million (the “Elwood Sale”).
For the three months ended March 31, 2016, we recorded $2 million in equity earnings related to our investment in Elwood which is reflected in Earnings from unconsolidated investments in our unaudited consolidated statements of operations. For the three months ended March 31, 2016, we received distributions of $8 million, all of which was considered to be a return of investment using the accumulated earnings approach and reflected as Distributions from unconsolidated investments in our unaudited consolidated statements of cash flows.

10

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Note 5—Risk Management Activities, Derivatives and Financial Instruments
The nature of our business involves commodity market and financial risks.  Specifically, we are exposed to commodity price variability related to our power generation business.  Our commercial team manages these commodity price risks with financially and physically settled contracts consistent with our commodity risk management policy.  Our treasury team manages our interest rate risk. 
Our commodity risk management policy gives us the flexibility to sell energy and capacity and purchase fuel through a combination of spot market sales and near-term contractual arrangements (generally over a rolling one- to three-year time frame).  Our commodity risk management goal is to protect cash flow in the near-term while keeping the ability to capture value longer-term. 
Many of our contractual arrangements are derivative instruments and are accounted for at fair value as part of Revenues in our unaudited consolidated statements of operations.  We have other contractual arrangements such as capacity forward sales arrangements, tolling arrangements, fixed price coal purchases, and retail power sales, which do not receive recurring fair value accounting treatment because these arrangements do not meet the definition of a derivative or are designated as “normal purchase, normal sale,” in accordance with ASC 815, Derivatives and Hedging.  As a result, the gains and losses with respect to these arrangements are not reflected in the unaudited consolidated statements of operations until the delivery occurs.
 Quantitative Disclosures Related to Financial Instruments and Derivatives
As of March 31, 2017, we had net purchases and sales of derivative contracts outstanding in the following quantities:
Contract Type
 
Quantity
 
Unit of Measure
 
Fair Value (1)
(dollars and quantities in millions)
 
Purchases (Sales)
 
 
 
Asset (Liability)
Commodity contracts:
 
 

 
 
 
 

Electricity derivatives (2)
 
(71
)
 
MWh
 
$
(40
)
Electricity basis derivatives (3)
 
(19
)
 
MWh
 
$
(1
)
Natural gas derivatives (2)
 
432

 
MMBtu
 
$
54

Natural gas basis derivatives
 
139

 
MMBtu
 
$
(4
)
Physical heat rate derivatives
 
144/(16)

 
MMBtu/MWh
 
$
8

Emissions derivatives
 
10

 
Metric Ton
 
$
(13
)
Interest rate swaps
 
767

 
U.S. Dollar
 
$
(23
)
Common stock warrants (4)
 
24

 
Warrant
 
$
(6
)
__________________________________________
(1)
Includes both asset and liability risk management positions but excludes margin and collateral netting of $66 million.
(2)
Mainly comprised of swaps and physical forwards.
(3)
Comprised of FTRs and swaps.
(4)
Each warrant is convertible into one share of Dynegy common stock.

11

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Derivatives on the Balance Sheet.  The following tables present the fair value and balance sheet classification of derivatives in our unaudited consolidated balance sheets as of March 31, 2017 and December 31, 2016. As of March 31, 2017 and December 31, 2016, there were no gross amounts available to be offset that were not offset in our unaudited consolidated balance sheets.
 
 
 
 
 
March 31, 2017
 
 
 
 
 
 
 
Gross amounts offset in the balance sheet
 
 
Contract Type
 
Balance Sheet Location
 
Gross Fair Value
 
Contract Netting
 
Collateral or Margin Received or Paid
 
Net Fair Value
(amounts in millions)
 
 
 
 
 
 
 
 
 
 
Derivative assets:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
Assets from risk management activities
 
$
336

 
$
(173
)
 
$

 
$
163

 
Total derivative assets
 
 
 
$
336

 
$
(173
)
 
$

 
$
163

 
 
 
 
 
 
 
 
 
 
 
 
Derivative liabilities:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
Liabilities from risk management activities
 
$
(332
)
 
$
173

 
$
66

 
$
(93
)
 
Interest rate contracts
 
Liabilities from risk management activities
 
(23
)
 

 

 
(23
)
 
Common stock warrants
 
Accrued liabilities, other current liabilities and other long-term liabilities
 
(6
)
 

 

 
(6
)
 
Total derivative liabilities
 
 
 
$
(361
)
 
$
173

 
$
66

 
$
(122
)
Total derivatives
 
 
 
$
(25
)
 
$

 
$
66

 
$
41


 
 
 
 
 
December 31, 2016
 
 
 
 
 
 
 
Gross amounts offset in the balance sheet
 
 
Contract Type
 
Balance Sheet Location
 
Gross Fair Value
 
Contract Netting
 
Collateral or Margin Received or Paid
 
Net Fair Value
(amounts in millions)
 
 
 
 
 
 
 
 
 
 
Derivative assets:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
Assets from risk management activities
 
$
311

 
$
(165
)
 
$

 
$
146

 
Total derivative assets
 
 
 
$
311

 
$
(165
)
 
$

 
$
146

 
 
 
 
 
 
 
 
 
 
 
 
Derivative liabilities:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
Liabilities from risk management activities
 
$
(329
)
 
$
165

 
$
54

 
$
(110
)
 
Interest rate contracts
 
Liabilities from risk management activities
 
(30
)
 

 

 
(30
)
 
Common stock warrants
 
Accrued liabilities and other current liabilities
 
(1
)
 

 

 
(1
)
 
Total derivative liabilities
 
 
 
$
(360
)
 
$
165

 
$
54

 
$
(141
)
Total derivatives
 
 
 
$
(49
)
 
$

 
$
54

 
$
5

Certain of our derivative instruments have credit limits that require us to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as our established credit limit with the respective counterparty. If our credit rating were to worsen, the counterparties could require us to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in our credit rating as well as the requirements of the individual counterparty. As of March 31, 2017, the aggregate fair value of all commodity derivative instruments containing credit-risk-related contingent features, in a liability position and not fully collateralized, is $9 million for which we have posted no collateral. Transactions with our clearing brokers are excluded as they are fully collateralized. Our

12

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

remaining derivative instruments do not have credit-related collateral contingencies as they are included within our first-lien collateral program.
The following table summarizes our cash collateral posted as of March 31, 2017 and December 31, 2016, within Prepayments and other current assets in our unaudited consolidated balance sheets and the amount applied against short-term risk management activities:
Location on Balance Sheet
 
March 31, 2017
 
December 31, 2016
(amounts in millions)
 
 
 
 
Gross collateral posted with counterparties
 
$
101

 
$
116

  Less: Collateral netted against risk management liabilities
 
66

 
54

Net collateral within Prepayments and other current assets
 
$
35

 
$
62

Impact of Derivatives on the Unaudited Consolidated Statements of Operations
We elect not to designate derivatives related to our power generation business and interest rate instruments as cash flow or fair value hedges.  Thus, we account for changes in the fair value of these derivatives within our unaudited consolidated statements of operations.
Our unaudited consolidated statements of operations for the three months ended March 31, 2017 and 2016 include the impact of derivative financial instruments as presented below:
Derivatives Not Designated as Hedges
 
Location of Gain (Loss)
Recognized in Income on
Derivatives
 
Three Months Ended March 31,
 
 
2017
 
2016
(amounts in millions)
 
 
 
 
 
 
Commodity contracts
 
Revenues
 
$
184

 
$
192

Interest rate contracts
 
Interest expense
 
$
2

 
$
(8
)
Common stock warrants
 
Other income and (expense), net
 
$
12

 
$
1

Note 6—Fair Value Measurements  
We apply the market approach for recurring fair value measurements, employing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  We have consistently used the same valuation techniques for all periods presented.  Please read Note 2Summary of Significant Accounting PoliciesFair Value Measurements in our Form 10-K for further discussion.

13

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2017 and December 31, 2016, and are presented on a gross basis before consideration of amounts netted under master netting agreements and the application of collateral and margin paid:
 
 
Fair Value as of March 31, 2017
 (amounts in millions)
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets:
 
 

 
 

 
 

 
 

Assets from commodity risk management activities:
 
 

 
 

 
 

 
 

Electricity derivatives
 
$

 
$
161

 
$
10

 
$
171

Natural gas derivatives
 

 
131

 
16

 
147

Physical heat rate derivatives
 

 
17

 

 
17

Emissions derivatives
 

 
1

 

 
1

Total assets from commodity risk management activities
 
$

 
$
310

 
$
26

 
$
336

Liabilities:
 
 

 
 

 
 

 
.

Liabilities from commodity risk management activities:
 
 

 
 

 
 

 
 

Electricity derivatives
 
$

 
$
(185
)
 
$
(27
)
 
$
(212
)
Natural gas derivatives
 

 
(79
)
 
(18
)
 
(97
)
Physical heat rate derivatives
 

 
(9
)
 

 
(9
)
Emissions derivatives
 

 
(14
)
 

 
(14
)
Total liabilities from commodity risk management activities
 

 
(287
)
 
(45
)
 
(332
)
Liabilities from interest rate contracts
 

 
(23
)
 

 
(23
)
Liabilities from outstanding common stock warrants
 
(6
)
 

 

 
(6
)
Total liabilities
 
$
(6
)
 
$
(310
)
 
$
(45
)
 
$
(361
)

 
 
 
Fair Value as of December 31, 2016
 (amounts in millions)
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets:
 
 

 
 

 
 

 
 

Assets from commodity risk management activities:
 
 

 
 

 
 

 
 

Electricity derivatives
 
$

 
$
118

 
$
20

 
$
138

Natural gas derivatives
 

 
169

 
4

 
173

Total assets from commodity risk management activities
 
$

 
$
287

 
$
24

 
$
311

Liabilities:
 
 

 
 

 
 

 
 

Liabilities from commodity risk management activities:
 
 

 
 

 
 

 
 

Electricity derivatives
 
$

 
$
(245
)
 
$
(12
)
 
$
(257
)
Natural gas derivatives
 

 
(52
)
 
(10
)
 
(62
)
Emissions derivatives
 

 
(10
)
 

 
(10
)
Total liabilities from commodity risk management activities
 

 
(307
)
 
(22
)
 
(329
)
Liabilities from interest rate contracts
 

 
(30
)
 

 
(30
)
Liabilities from outstanding common stock warrants
 
(1
)
 

 

 
(1
)
Total liabilities
 
$
(1
)
 
$
(337
)
 
$
(22
)
 
$
(360
)
Level 3 Valuation Methods. The electricity derivatives classified within Level 3 include financial swaps executed in illiquid trading locations or on long dated contracts, capacity contracts and FTRs.  The curves used to generate the fair value of the financial swaps are based on basis adjustments applied to forward curves for liquid trading points, while the curves for the capacity deals are based upon auction results in the marketplace, which are infrequently executed. The forward market price of FTRs is derived using historical congestion patterns within the marketplace and heat rate derivative valuations are derived using a Black-Scholes spread model, which uses forward natural gas and power prices, market implied volatilities, and modeled correlation

14

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

values. The natural gas derivatives classified within Level 3 include financial swaps, basis swaps, and physical purchases executed in illiquid trading locations or on long dated contracts.
Sensitivity to Changes in Significant Unobservable Inputs for Level 3 Valuations. The significant unobservable inputs used in the fair value measurement of our commodity instruments categorized within Level 3 of the fair value hierarchy include estimates of forward congestion, power price spreads, natural gas and coal pricing, and the difference between our plant locational prices to liquid hub prices. Power price spreads, natural gas and coal pricing, and the difference between our plant locational prices to liquid hub prices are generally based on observable markets where available, or derived from historical prices and forward market prices from similar observable markets when not available. Increases in the price of the spread on a buy or sell position in isolation would result in a higher/lower fair value measurement. The significant unobservable inputs used in the valuation of Dynegy’s contracts classified as Level 3 as of March 31, 2017 are as follows:
Transaction Type
 
Quantity
 
Unit of Measure
 
Net Fair Value
 
Valuation Technique
 
Significant Unobservable Input
 
Significant Unobservable Input Range
(dollars in millions)
 
 
 
 
 
 
 
 
 
 
 
 
Electricity derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Forward contracts—power (1)
 
(19
)
 
Million MWh
 
$
(17
)
 
Basis spread + liquid location
 
Basis spread
 
$4.25 - $6.25
FTRs
 
(12
)
 
Million MWh
 
$

 
Historical congestion
 
Forward price
 
$0 - $6.00
Natural gas derivatives (1)
 
119

 
Million MMBtu
 
$
(2
)
 
Illiquid location fixed price
 
Forward price
 
$2.50 - $3.00
__________________________________________
(1)
Represents forward financial and physical transactions at illiquid pricing locations and long-dated contracts.
The following tables set forth a reconciliation of changes in the fair value of financial instruments classified as Level 3 in the fair value hierarchy:
 
 
Three Months Ended March 31, 2017
(amounts in millions)
 
Electricity
Derivatives
 
Natural Gas Derivatives
 
Total
Balance at December 31, 2016
 
$
8

 
$
(6
)
 
$
2

Acquired derivatives
 
1

 

 
1

Total gains (losses) included in earnings
 
(46
)
 
11

 
(35
)
Settlements (1)
 
20

 
(7
)
 
13

Balance at March 31, 2017
 
$
(17
)
 
$
(2
)
 
$
(19
)
Unrealized gains (losses) relating to instruments held as of March 31, 2017
 
$
(46
)
 
$
11

 
$
(35
)

 
 
Three Months Ended March 31, 2016
(amounts in millions)
 
Electricity
Derivatives
 
Natural Gas Derivatives
 
Coal Derivatives
 
Total
Balance at December 31, 2015
 
$
(18
)
 
$
(32
)
 
$
2

 
$
(48
)
Total gains included in earnings
 
8

 
5

 

 
13

Settlements (1)
 
(7
)
 
9

 
(1
)
 
1

Balance at March 31, 2016
 
$
(17
)
 
$
(18
)
 
$
1

 
$
(34
)
Unrealized gains relating to instruments held as of March 31, 2016
 
$
8

 
$
5

 
$

 
$
13

_________________________________________
(1)
For purposes of these tables, we define settlements as the beginning of period fair value of contracts that settled during the period.

15

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Gains and losses recognized for Level 3 recurring items are included in Revenues in our unaudited consolidated statements of operations for commodity derivatives.  We believe an analysis of commodity instruments classified as Level 3 should be undertaken with the understanding that these items generally serve as economic hedges of our power generation portfolio.  We did not have any transfers between Level 1, Level 2 and Level 3 for the three months ended March 31, 2017 and 2016.
Nonfinancial Assets and Liabilities.  Nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of such assets and liabilities and their placement within the fair value hierarchy.
During the three months ended March 31, 2017, as a result of impairment testing, we measured our Killen facility at fair value using a discounted cash flow model classified as Level 3 within the fair value hierarchy. See Note 9—Property, Plant and Equipment for further discussion. During the three months ended March 31, 2017, we fair valued the ENGIE Acquisition. See Note 3—Acquisitions and Divestitures for further discussion and for the fair value hierarchy classifications of the valuation.
Fair Value of Financial Instruments.  The following table discloses the fair value of financial instruments which are not recognized at fair value in our unaudited consolidated balance sheets.  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 March 31, 2017 and December 31, 2016, respectively.
 
 
 
 
March 31, 2017
 
December 31, 2016
(amounts in millions)
 
Fair Value Hierarchy
 
Carrying
Amount
 
Fair
 Value
 
Carrying
Amount
 
Fair
 Value
Dynegy Inc.:
 
 
 
 
 
 
 
 
 
 
Tranche C-1 Term Loan, due 2024 (1)
 
Level 2
 
$
(2,130
)
 
$
(2,230
)
 
$
(1,994
)
 
$
(2,025
)
Tranche B-2 Term Loan, due 2020 (1)
 
Level 2
 
$

 
$

 
$
(219
)
 
$
(225
)
Revolving Facility (1)
 
Level 2
 
$
(300
)
 
$
(300
)
 
$

 
$

6.75% Senior Notes, due 2019 (1)
 
Level 2
 
$
(2,084
)
 
$
(2,163
)
 
$
(2,083
)
 
$
(2,137
)
7.375% Senior Notes, due 2022 (1)
 
Level 2
 
$
(1,732
)
 
$
(1,728
)
 
$
(1,731
)
 
$
(1,665
)
5.875% Senior Notes, due 2023 (1)
 
Level 2
 
$
(493
)
 
$
(456
)
 
$
(492
)
 
$
(431
)
7.625% Senior Notes, due 2024 (1)
 
Level 2
 
$
(1,236
)
 
$
(1,194
)
 
$
(1,237
)
 
$
(1,156
)
8.034% Senior Notes, due 2024 (1)
 
Level 2
 
$
(182
)
 
$
(171
)
 
$

 
$

8.00% Senior Notes, due 2025 (1)
 
Level 2
 
$
(738
)
 
$
(718
)
 
$
(738
)
 
$
(703
)
7.00% Amortizing Notes, due 2019 (TEUs) (1)
 
Level 2
 
$
(71
)
 
$
(75
)
 
$
(78
)
 
$
(90
)
Forward capacity agreement (1)
 
Level 3
 
$
(207
)
 
$
(207
)
 
$
(205
)
 
$
(205
)
Inventory financing agreements
 
Level 3
 
$
(61
)
 
$
(61
)
 
$
(129
)
 
$
(127
)
Equipment financing agreements (1)
 
Level 3
 
$
(83
)
 
$
(83
)
 
$
(73
)
 
$
(73
)
Genco:
 
 
 
 
 
 
 
 
 
 
Liabilities subject to compromise (2)
 
Level 3
 
$

 
$

 
$
(825
)
 
$
(366
)
__________________________________________
(1)
Carrying amounts include unamortized discounts and debt issuance costs. Please read Note 12—Debt for further discussion.
(2)
Carrying amounts represent the Genco senior notes that have been classified as liabilities subject to compromise as of December 31, 2016. The fair value of the senior notes was equal to the Genco Plan consideration and is a Level 3 valuation due to a lack of observable inputs that make up the consideration. Please read Note 22—Genco Chapter 11 Bankruptcy in our Form 10-K for further details.

16

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Note 7—Cash Flow Information
The supplemental disclosures of our non-cash investing and financing information are as follows:
 
 
Three Months Ended March 31,
(amounts in millions)
 
2017
 
2016
Change in capital expenditures included in accounts payable
 
$
5

 
$
1

Change in capital expenditures pursuant to an equipment financing agreement
 
$
9

 
$
1

Issuance of 2017 Warrants
 
$
17

 
$

Issuance of senior notes as part of the Genco restructuring
 
$
182

 
$

Non-cash working capital adjustment to purchase price of the ENGIE acquisition
 
$
15

 
$

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within our unaudited consolidated balance sheets that sum to the total of the same such amounts shown in our unaudited consolidated statements of cash flows:
 
 
Three Months Ended March 31,
(amounts in millions)
 
2017
 
2016
Cash and cash equivalents
 
$
467

 
$
821

Restricted cash included in current assets related to collateral
 

 
37

Total cash, cash equivalents and restricted cash
 
$
467

 
$
858

    
Note 8—Inventory
A summary of our inventories is as follows: 
(amounts in millions)
 
March 31, 2017
 
December 31, 2016
Materials and supplies
 
$
247

 
$
182

Coal (1)
 
225

 
238

Fuel oil (1)
 
22

 
17

Gas
 
13

 

Emissions allowances (2)
 
6

 
8

Total
 
$
513

 
$
445

__________________________________________
(1)
At March 31, 2017, approximately $3 million and $9 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2016, approximately $44 million and $12 million of the coal and fuel oil inventory, respectively, were part of an inventory financing agreement. Please read Note 12—DebtBrayton Point Inventory Financing for further discussion.
(2)
At March 31, 2017 and December 31, 2016, a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read Note 12—DebtEmissions Repurchase Agreements for further discussion.
Note 9—Property, Plant and Equipment
A summary of our property, plant and equipment is as follows:
(amounts in millions)

March 31, 2017

December 31, 2016
Power generation

$
10,072


$
7,537

Buildings and improvements

1,184


944

Office and other equipment

117


98

Property, plant and equipment

11,373


8,579

Accumulated depreciation

(1,654
)

(1,458
)
Property, plant and equipment, net

$
9,719


$
7,121


17

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Impairments
Killen. On March 20, 2017, Dayton Power and Light Co., the partner and operator of Killen, announced the shutdown of its Killen generation facility by June 2018. We performed an impairment test which resulted in a negative fair value. As a result, we recorded an impairment charge of approximately $20 million recorded to Impairments in our unaudited consolidated statements of operations for the three months ended March 31, 2017.
Note 10—Joint Ownership of Generating Facilities
We hold ownership interests in certain jointly owned generating facilities. We are entitled to the proportional share of the generating capacity and the output of each unit equal to our ownership interests. We pay our share of capital expenditures, fuel inventory purchases, and operating expenses, except in certain instances where agreements have been executed to limit certain joint owners’ maximum exposure to additional costs. Our share of revenues and operating costs of the jointly owned generating facilities is included within the corresponding financial statement line items in our unaudited consolidated statements of operations.
The following tables present the ownership interests of the jointly owned facilities as of March 31, 2017 and December 31, 2016 included in our unaudited consolidated balance sheets. Each facility is co-owned with one or more other generation companies.


March 31, 2017
(dollars in millions)

Ownership Interest

Property, Plant and Equipment

Accumulated Depreciation

Construction Work in Progress

Total
Miami Fort

64.0
%

$
208


$
(44
)

$
4


$
168

Stuart (1)(2)

39.0
%

$


$


$
3


$
3

Conesville (1)

40.0
%

$
61


$
(3
)

$
6


$
64

Zimmer

46.5
%

$
116


$
(29
)

$
6


$
93

Killen (1)(2)(3)

33.0
%

$


$


$


$


 
 
December 31, 2016
(dollars in millions)
 
Ownership Interest
 
Property, Plant and Equipment
 
Accumulated Depreciation
 
Construction Work in Progress
 
Total
Miami Fort
 
64.0
%
 
$
207

 
$
(39
)
 
$
4

 
$
172

Stuart
 
39.0
%
 
$

 
$

 
$
4

 
$
4

Conesville
 
40.0
%
 
$
61

 
$
(3
)
 
$
6

 
$
64

Zimmer
 
46.5
%
 
$
115

 
$
(25
)
 
$
6

 
$
96

Killen
 
33.0
%
 
$
19

 
$
(2
)
 
$
3

 
$
20

__________________________________________
(1)
Facilities not operated by Dynegy.
(2)
Scheduled to be retired by mid-2018.
(3)
Please read Note 9—Property, Plant and Equipment for further discussion of impairment recognized for the three months ended March 31, 2017.
On February 23, 2017, Dynegy reached an agreement with American Electric Power (“AEP”) to realign and consolidate each company’s ownership interests in the Conesville and Zimmer Power Stations in Ohio. Under the agreement, Dynegy will sell its 40 percent ownership interest in Conesville to AEP, and will acquire AEP’s 25.4 percent ownership interest in Zimmer. As a result, Dynegy will own 71.9 percent of the Zimmer facility and will no longer have an ownership interest in the AEP operated Conesville facility. No cash will be exchanged in the transaction and no additional debt will be incurred by either party. AEP will return a previously issued letter of credit totaling $58 million to Dynegy. The transaction is expected to close in the second half of 2017.
On April 21, 2017, Dynegy reached an agreement with AES Ohio Generation, LLC and The Dayton Power and Light Company (collectively, “AES”) under which Dynegy will purchase AES’ 28.1 percent interest in Zimmer and 36 percent interest

18

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

in Miami Fort for $50 million in cash and the assumption of certain liabilities, subject to customary adjustments. The transaction is expected to close in the second half of 2017.
Note 11—Intangible Assets and Liabilities
The following table summarizes the components of our intangible assets and liabilities as of March 31, 2017 and December 31, 2016:
 
 
March 31, 2017
 
December 31, 2016
(amounts in millions)
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Carrying Amount
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Carrying Amount
Intangible Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Electricity contracts
 
$
293

 
$
(219
)
 
$
74

 
$
260

 
$
(206
)
 
$
54

Gas transport contracts
 
29

 
(9
)
 
20

 
13

 
(6
)
 
7

Total intangible assets
 
$
322

 
$
(228
)
 
$
94

 
$
273

 
$
(212
)
 
$
61

 
 
 
 
 
 
 
 
 
 
 
 
 
Intangible Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Electricity contracts
 
$
(31
)
 
$
20

 
$
(11
)
 
$
(28
)
 
$
26

 
$
(2
)
Coal contracts
 
(49
)
 
44

 
(5
)
 
(49
)
 
42

 
(7
)
Coal transport contracts
 
(86
)
 
76

 
(10
)
 
(86
)
 
73

 
(13
)
Gas transport contracts
 
(60
)
 
9

 
(51
)
 
(41
)
 
8

 
(33
)
Gas storage contracts
 
(2
)
 

 
(2
)
 

 

 

Total intangible liabilities
 
$
(228
)
 
$
149

 
$
(79
)
 
$
(204
)
 
$
149

 
$
(55
)
Intangible assets and liabilities, net
 
$
94

 
$
(79
)
 
$
15

 
$
69

 
$
(63
)
 
$
6

The following table presents our amortization expense (revenue) of intangible assets and liabilities for the three months ended March 31, 2017 and 2016:
 
 
Three Months Ended March 31,
(amounts in millions)
 
2017
 
2016
Electricity contracts, net (1)
 
$
15

 
$
16

Coal contracts, net (2)
 
(2
)
 
(12
)
Coal transport contracts, net (2)
 
(2
)
 
(7
)
Gas transport contracts, net (2)
 

 
17

Total
 
$
11

 
$
14

__________________________________________
(1)
The amortization of these contracts is recognized in Revenues or Cost of sales in our unaudited consolidated statements of operations.
(2)
The amortization of these contracts is recognized in Cost of sales in our unaudited consolidated statements of operations.

19

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

The following table summarizes the components of our contract based intangible assets and liabilities recorded in connection with the ENGIE Acquisition in February 2017:
(amounts in millions/months)
 
Gross Carrying Amount
 
Weighted-Average Amortization Period
Intangible Assets:
 
 
 
 
Electricity contracts
 
$
34

 
39
Gas transport contracts
 
16

 
47
Total intangible assets
 
$
50

 
41
 
 
 
 
 
Intangible Liabilities:
 
 
 
 
Electricity contracts
 
$
(11
)
 
32
Gas contracts
 

 
1
Gas transport contracts
 
(17
)
 
35
Gas storage contracts
 
(2
)
 
13
Total intangible liabilities
 
$
(30
)
 
33
Total intangible assets and liabilities, net
 
$
20

 
 
Amortization expense (revenue), net related to intangible assets and liabilities recorded in connection with the ENGIE Acquisition for the next five years as of March 31, 2017 is as follows: 2017$(7) million, 2018$8 million, 2019$17 million, 2020$4 million and 2021$(1) million.

20

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Note 12—Debt
A summary of our long-term debt is as follows:
(amounts in millions)
 
March 31, 2017
 
December 31, 2016
Secured Obligations:
 
 
 
 
Tranche C-1 Term Loan, due 2024 (1)
 
$
2,224

 
$
2,000

Tranche B-2 Term Loan, due 2020
 

 
224

Revolving Facility
 
300

 

Forward Capacity Agreements
 
230

 
219

Inventory Financing Agreements
 
61

 
129

Subtotal secured obligations
 
2,815

 
2,572

Unsecured Obligations:
 
 
 
 
7.00% Amortizing Notes, due 2019 (TEUs)
 
73

 
80

6.75% Senior Notes, due 2019
 
2,100

 
2,100

7.375% Senior Notes, due 2022
 
1,750

 
1,750

5.875% Senior Notes, due 2023
 
500

 
500

7.625% Senior Notes, due 2024
 
1,250

 
1,250

8.034% Senior Notes, due 2024 (2)
 
182

 

8.00% Senior Notes, due 2025
 
750

 
750

Equipment Financing Agreements
 
110

 
97

Subtotal unsecured obligations
 
6,715

 
6,527

Total debt obligations
 
9,530

 
9,099

Unamortized debt discounts and issuance costs
 
(213
)
 
(120
)
 
 
9,317

 
8,979

Less: Current maturities, including unamortized debt discounts and issuance costs, net
 
117

 
201

Total Long-term debt
 
$
9,200

 
$
8,778

__________________________________________
(1)
At December 31, 2016, the $2.0 billion Tranche C Term Loan was held by Dynegy Finance IV. Upon the close of the ENGIE Acquisition, this debt obligation became Dynegy Inc.’s secured obligation.
(2)
On the Genco Emergence Date, we issued the $182 million, 8.034 percent seven-year unsecured senior notes due 2024.
Credit Agreement
As of March 31, 2017, we had a $3.769 billion credit agreement, as amended, that consisted of (i) a $2.224 billion seven-year senior secured term loan facility (the “Tranche C-1 Term Loan”) and (ii) $1.545 billion in senior secured revolving credit facilities (the “Revolving Facility,” and collectively with the Tranche C-1 Term Loan the “Credit Agreement”). During the three months ended March 31, 2017, we made the following changes to the Credit Agreement:
On January 10, 2017, we amended the Credit Agreement (Fourth Amendment) to increase the revolver capacity by $45 million and to extend the maturity date on $450 million in revolver capacity to 2021, which was effective upon the ENGIE Acquisition Closing Date.
On the ENGIE Acquisition Closing Date, we amended the Credit Agreement (Fifth Amendment) to (i) reduce the interest rate applicable to the Tranche C Term Loan by 75 basis points and (ii) extend the maturity to 2024 of the existing Tranche B-2 Term Loan through the exchange of the outstanding initial Tranche B-2 Term Loan for the $2.224 billion Tranche C-1 Term Loan.
At March 31, 2017, there was $300 million drawn on the Revolving Facility. We also had outstanding letters of credit (“LCs”) of approximately $367 million, which reduce the amount available under the Revolving Facility. The Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a

21

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Senior Secured Leverage Ratio (as defined in the Credit Agreement) calculated on a rolling four quarters basis. Under the Credit Agreement, if Dynegy utilizes 25 percent or more of its Revolving Facility, Dynegy must be in compliance with the Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio of 4.00:1.00. Our revolver usage at March 31, 2017 was 43 percent of the aggregate revolver commitment due to outstanding LCs and revolver draws. Based on the calculation outlined in the Credit Agreement, we were in compliance with these covenants as of March 31, 2017.
Under the terms of the Credit Agreement, existing balances under our Forward Capacity Agreement, Inventory Financing Agreements, and Equipment Financing Agreements are excluded from Net Debt.
Interest Rate Swaps. During 2017, we amended our interest rate swaps to more closely match the terms of our Tranche C-1 Term Loan. The swaps have an aggregate notional value of approximately $767 million at an average fixed rate of 3.03 percent and expire during the second quarter of 2020. In lieu of paying the breakage fees related to terminating the old swaps and issuing the new swaps, the costs were incorporated into the terms of the new swaps. As a result, any cash flows related to the settlement of the swaps are reflected as a financing activity in our unaudited consolidated statements of cash flows.
Amortizing Notes
On June 21, 2016, in connection with the issuance of the tangible equity units (“TEUs”), Dynegy issued the Amortizing Notes with a principal amount of approximately $87 million. The Amortizing Notes mature on July 1, 2019. Each installment payment per Amortizing Note will be paid in cash and will constitute a partial repayment of principal and a payment of interest, computed at an annual rate of 7 percent. Interest will be calculated on the basis of a 360 day year consisting of twelve 30 day months. Payments will be applied first to the interest due and payable and then to the reduction of the unpaid principal amount, allocated as set forth in the Indenture.
The Indenture limits, among other things, the ability of Dynegy to consolidate, merge, sell, or dispose all or substantially all of its assets. If a fundamental change occurs, or if Dynegy elects to settle the prepaid stock contracts (“SPCs”) early, then the holders of the Amortizing Notes will have the right to require Dynegy to repurchase the Amortizing Notes at a repurchase price equal to the principal amount of the Amortizing Notes as of the repurchase date (as described in the supplemental indenture) plus accrued and unpaid interest. The Indenture also contains customary events of default which would permit the holders of the Amortizing Notes to declare those Amortizing Notes to be immediately due and payable if not cured within applicable grace periods, including the failure to make timely installment payments on the Amortizing Notes or other material indebtedness, the failure to satisfy covenants, and specified events of bankruptcy and insolvency.
Letter of Credit Facilities
Dynegy has an LC Reimbursement Agreement with Macquarie Bank Limited (“Macquarie Bank”), for an LC in an amount not to exceed $55 million. The expiry date of the facility was extended in August 2016 to September 19, 2017. At March 31, 2017, there was $55 million outstanding under this LC.
Illinois Power Marketing Company (“IPM”) has an LC and reimbursement agreement with an issuing bank in which the issuing bank agrees to issue standby LCs in stated amounts not to exceed $25 million to support performance obligations and other general corporate activities of IPM and Illinois Power Resources Generating, LLC. Upon the Emergence Date, the IPM LC facility was collateralized by an $18 million LC issued under the Revolving Facility, and previous cash collateral backing the facility was released and returned to Dynegy. As of March 31, 2017, there were $14 million in LCs outstanding under this facility.
Following the ENGIE Acquisition Closing Date, Dynegy entered into a Letter of Credit Reimbursement Agreement with an issuing bank, pursuant to which the issuing bank agreed to provide LCs in an amount not to exceed $50 million. The facility has a one-year tenor and may be extended at the Lender’s discretion for up to four additional one-year terms. As of March 31, 2017, there were $40 million in LCs outstanding under this facility.
Forward Capacity Agreement
On March 29, 2017, we replaced our existing bilateral contract with a financial institution to sell a portion of our forward cleared PJM capacity auction volumes from PJM during the Planning Year 2017-2018, in the amount of $110 million, with a contract to sell a portion of our forward cleared PJM capacity auction volumes from PJM during the Planning Year 2019-2020 in the amount of $121 million. Dynegy will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. Together with the previous sale of a portion, or $109 million, of our capacity payments from PJM during the Planning Year 2018-2019, which was unchanged, the transaction is accounted for as a debt issuance of $230 million with an implied interest rate of 4.7 percent.

22

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Inventory Financing Agreements
Brayton Point Inventory Financing. Our Brayton Point facility has an inventory financing agreement (the “Inventory Financing Agreement”) for coal and fuel oil inventories, consisting of a debt obligation for existing and subsequent inventories, as well as a $15 million line of credit. Balances in excess of the $15 million line of credit are cash collateralized.
As the materials are purchased and delivered to our facilities, our debt obligation and line of credit increase based on the then market rate of the materials, transportation costs, and other expenses. The debt obligation increases for 85 percent of the total cost of the coal and for 90 percent of the total cost of the fuel oil. The line of credit increases for the remaining 15 percent and 10 percent for coal and oil costs, respectively. We repay the debt obligation and line of credit from revenues received, at the then market price, for the amount of the materials consumed, on a weekly basis.
As of March 31, 2017, there was $13 million outstanding under this agreement. Both the debt obligation related to coal and the base level of fuel oil, as well as the line of credit, bear interest at an annual interest rate of the 3-month LIBOR plus 5.6 percent. An availability fee is calculated on a per annum rate of 0.25 percent. Additionally, we had no collateral postings. The Inventory Financing Agreement terminates, and the remaining obligation, if any, becomes due and payable on May 31, 2017.
Emissions Repurchase Agreements. In August 2015, we entered into two repurchase transactions with a third party in which we sold approximately $78 million of RGGI inventory and received cash. In February 2017, we repurchased approximately $30 million of the previously sold RGGI inventory. We are obligated to repurchase the remaining inventory in February 2018 at a specified price with an annualized carry cost of approximately 3.49 percent. As of March 31, 2017, there was $48 million, in aggregate, outstanding under these agreements.
Equipment Financing Agreements
Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency, and availability of our generation units. We have financed these parts and equipment under agreements with maturities ranging from 2017 to 2025. The portion of future payments attributable to principal will be classified as cash outflows from financing activities, and the portion of future payments attributable to interest will be classified as cash outflows from operating activities in our unaudited consolidated statements of cash flows. The related assets were recorded at the net present value of the payments of $83 million. The $27 million discount is currently being amortized as interest expense over the life of the payments.
Note 13—Commitments and Contingencies
 Legal Proceedings
Set forth below is a summary of our material ongoing legal proceedings. We record accruals for estimated losses from contingencies when available information indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated.  In addition, we disclose matters for which management believes a material loss is reasonably possible.  In all instances, management has assessed the matters below based on current information and made judgments concerning their potential outcome, giving consideration to the nature of the claim, the amount, if any, 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.
In addition to the matters discussed below, we are party to other routine proceedings arising in the ordinary course of business.  Any accruals or estimated losses related to these matters are not material. In management’s judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations, or cash flows.
Gas Index Pricing Litigation.  We, through our subsidiaries, and other energy companies are named as defendants in several lawsuits claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to various index publications from 2000-2002. The cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices in three states (Kansas, Missouri, and Wisconsin) during the relevant time period. The cases are consolidated in a multi-district litigation proceeding pending in the United States District Court for Nevada.  On March 30, 2017, the court denied Plaintiffs’ motion to certify a class action, which may be subject to an interlocutory appeal requested by the plaintiffs on April 14, 2017.  At this time we cannot reasonably estimate a potential loss.

23

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Advatech Dispute. On September 2, 2016, Genco terminated its Second Amended and Restated Newton Flue Gas Desulfurization System Engineering, Procurement, Construction and Commissioning Services Contract dated as of December 15, 2014 with Advatech, LLC. Advatech issued Genco its final invoice on September 30, 2016 totaling $81 million. Genco contested the invoice on October 3, 2016 and believes the proper amount is less than $1 million. On October 27, 2016, Advatech initiated the dispute resolution process under the Contract and filed for arbitration on March 17, 2017. Settlement discussions required under the dispute resolution process have been unsuccessful. We believe that the risk of a material loss related to this dispute to be remote.
Other Contingencies
MISO 2015-2016 Planning Resource Auction. In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (“PRA”) conducted by MISO. Dynegy is a named party in one of the complaints. 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.  We filed our Answer to these complaints and believe that we complied fully with the terms of the MISO tariff in connection with the 2015-2016 PRA, disputed the allegations, and will defend our actions vigorously. 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.
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. 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.
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 Newton facility NOV. In September 2016, we retired Newton Unit 2.
CAA Section 114 Information Requests. In 2014, we received an information request from the EPA concerning our Wood River facility’s compliance with the Illinois State Implementation Plan (“SIP”) and associated permits. We responded to the EPA’s request and believe that there are no issues with Wood River’s compliance, but we are unable to predict the EPA’s response, if any. As of June 1, 2016, our Wood River facility has been retired.
In April 2017, we received an information request from the EPA concerning CAA compliance, including New Source Review requirements, at the Armstrong facility, which we acquired in February 2017. We are in the process of responding to that request.

24

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

CAA Notices of Violation. In December 2014, the EPA issued an NOV alleging violation of opacity standards at the Zimmer facility, which we co-own and operate. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio SIP, and the station’s air permits involving standards applicable to opacity, sulfur dioxide, sulfuric acid mist, and heat input. The NOVs remain unresolved. The EPA also issued NOVs in December 2014 for Killen and Stuart, and in February 2017 for Stuart, alleging violations of opacity standards. We jointly own but do not operate the Killen and Stuart facilities.
Edwards CAA Citizen Suit. In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for the Central District of Illinois alleging violations of opacity and particulate matter limits at our IPH segment’s Edwards facility. In August 2016, the District Court granted the plaintiffs’ motion for summary judgment on certain liability issues. We filed a motion seeking interlocutory appeal of the court’s summary judgment ruling. In February 2017, the appellate court denied our motion for interlocutory appeal. The District Court has scheduled the remedy phase trial for October 2018. We dispute the allegations and will defend the case vigorously.
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.
Stuart National Pollutant Discharge Elimination System (“NPDES”) Permit Appeal.  In January 2013, the Ohio EPA reissued the NPDES permit for the jointly owned Stuart facility.  The operator of Stuart, The Dayton Power and Light Company, appealed various aspects of the permit, including provisions regarding thermal discharge limitations, to the Ohio Environmental Review Appeals Commission.  Depending on the outcome of the appeal, the effects on Stuart’s operations could be material. 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 this matter.
MISO Segment Groundwater. In 2012, the Illinois EPA (“IEPA”) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities.
At Baldwin, with approval of the IEPA, we performed a comprehensive evaluation of the Baldwin Coal Combustion Residuals (“CCR”) surface impoundment system beginning in 2013. Based on the results of that evaluation, we recommended to the IEPA in 2014 that the closure process for the inactive east CCR surface impoundment begin and that a geotechnical investigation of the existing soil cap on the inactive old east CCR surface impoundment be undertaken. We also submitted a supplemental groundwater modeling report that indicates no known offsite water supply wells will be impacted under the various Baldwin CCR surface impoundment closure scenarios modeled. In 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We are working towards implementation of the closure plan.
We initiated an investigation at Baldwin in 2011 at the request of the IEPA to determine if the facility’s CCR surface impoundment system impacts offsite groundwater. Results of the offsite groundwater quality investigation, as submitted to the IEPA in 2012, indicate two localized areas where Class I groundwater standards were exceeded. Based on the data and groundwater flows, we do not believe that the exceedances are attributable to the Baldwin CCR surface impoundment system.
At our retired Vermilion facility, which is not subject to the CCR rule, we submitted proposed corrective action plans for two CCR surface impoundments (i.e., the old east and the north CCR surface impoundments) to the IEPA in 2012. Our hydrogeological investigation indicates that these two CCR surface impoundments impact groundwater quality onsite and that such groundwater migrates offsite to the north of the property and to the adjacent Middle Fork of the Vermilion River.  The proposed corrective action plans recommend closure in place of both CCR surface impoundments and include an application to the IEPA to establish a groundwater management zone while impacts from the facility are mitigated.  In 2014, we submitted a revised corrective action plan for the old east CCR surface impoundment. We await IEPA action on our proposed corrective action plans. Our estimated cost of the recommended closure alternative for both the Vermilion old east and north CCR surface impoundments, including post-closure care, is approximately $10 million.
If remediation measures concerning groundwater are necessary in the future at either Baldwin or Vermilion, 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.
IPH Segment Groundwater. Groundwater monitoring results indicate that the CCR surface impoundments at each of the IPH segment facilities potentially impact onsite groundwater. In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. In 2015, we submitted an assessment

25

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

monitoring report to the IEPA that identifies the Newton facility’s inactive unlined landfill as the likely source of groundwater quality exceedances at the facility’s active CCR landfill. In August 2016, the IEPA approved the report. We are monitoring groundwater in accordance with IEPA’s approval.
If remediation measures concerning groundwater are necessary at any of our IPH facilities, IPH may incur significant costs that could have a material adverse effect on its 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.
Dam Safety Assessment Reports. In response to the failure at the Tennessee Valley Authority’s Kingston plant, the EPA initiated a nationwide investigation of the structural integrity of CCR surface impoundments in 2009. The EPA assessments found all of our surface impoundments to be in satisfactory or fair condition, with the exception of the surface impoundments at the Baldwin and Hennepin facilities.
In response to the Hennepin report, we made capital improvements to the Hennepin east CCR surface impoundment berms and notified the EPA of our intent to close the Hennepin west CCR surface impoundment. The preliminary estimated cost for closure of the west CCR surface impoundment, including post-closure monitoring, is approximately $5 million, which is reflected in our AROs. We performed further studies needed to support closure of the west CCR surface impoundment, submitted those studies to the IEPA in 2014 and await IEPA action.
In response to the Baldwin report, we notified the EPA in 2013 of our action plan, which included implementation of recommended operating practices and certain recommended studies. In 2014, we updated the EPA on the status of our Baldwin action plan, including the completion of certain studies and implementation of remedial measures and our ongoing evaluation of potential long-term measures in the context of our concurrent evaluation at Baldwin of groundwater corrective actions. At this time, to resolve the concerns raised in the EPA’s assessment report and as a result of the CCR rule, we plan to initiate closure of the Baldwin west fly ash CCR surface impoundment in 2017, which is reflected in our AROs.
Other Commitments
In conducting our operations, we routinely enter 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.
 Indemnifications and Guarantees
In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees.  Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales agreements and procurement and construction contracts.  Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party.  Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false.  While there is always the possibility of a loss related to such representations, warranties, indemnifications, and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote.  We have accrued no amounts with respect to the indemnifications as of March 31, 2017 because none were probable of occurring, nor could they be reasonably estimated.

26

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Note 14—Income Taxes
We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for significant, unusual, or extraordinary transactions.  Income taxes for significant, unusual, or extraordinary transactions are computed and recorded in the period that the specific transaction occurs. The income taxes related to income (loss) from continuing operations were as follows:
 
 
Three Months Ended March 31,
(amounts in millions)
 
2017
 
2016
Income tax benefit (expense) (1)
 
$
313

 
$
(16
)
 ______________________________________
(1)
The three months ended March 31, 2017 include a $317 million benefit for a partial release of our valuation allowance as a result of the ENGIE Acquisition. The benefit was offset by a $4 million expense due to tax exposures in jurisdictions in which we do not have an offsetting deferred tax asset. The three months ended March 31, 2016 include a $15 million charge to deferred state income tax expense as a result of a change to our corporate tax structure.
As of March 31, 2017, we continued to maintain a valuation allowance against our net deferred tax assets in each jurisdiction as they arise as there was not sufficient evidence to overcome our historical cumulative losses to conclude that it is more-likely-than-not our net deferred tax assets can be realized in the future.
We have also increased our unrecognized tax benefits by $66 million as a result of the ENGIE Acquisition for uncertain tax positions included in GSENA’s tax returns prior to our ownership.
Note 15—Pension and Other Post-Employment Benefit Plans
We sponsor and administer defined benefit plans and defined contribution plans for the benefit of our employees and also provide other post-employment benefits to retirees who meet age and service requirements, which are further described in Note 19—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans in our Form 10-K.
In the first quarter of 2017, the Dynegy pension and other post-employment plans were amended as a result of negotiations with former Duke Midwest union participants, IBEW Local 1347. As part of these amendments, the participants’ previous pension plan accrued benefits will be frozen as of December 31, 2017 and will begin accruing on January 1, 2018 with a minimum interest crediting rate of 4 percent. Other post-employment plans were amended to provide retiree medical plan benefits to only certain participants as of January 1, 2018. As a result of these amendments, we remeasured our benefit obligations and funded status of the affected plans and recorded a net-of-tax gain of approximately $15 million through accumulated other comprehensive income.
Components of Net Periodic Benefit Cost (Gain).  The components of net periodic benefit cost (gain) were as follows:
 
 
Pension Benefits
 
Other Benefits
 
 
Three Months Ended March 31,
(amounts in millions)
 
2017
 
2016
 
2017
 
2016
Service cost benefits earned during period
 
$
4

 
$
4

 
$

 
$

Interest cost on projected benefit obligation
 
5

 
5

 

 
1

Expected return on plan assets
 
(6
)
 
(6
)
 

 
(1
)
Amortization of prior service credit
 

 

 
(1
)
 
(1
)
Net periodic benefit cost (gain)
 
$
3

 
$
3

 
$
(1
)
 
$
(1
)

27

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Note 16—Stockholders' Equity
Preferred Stock
We pay quarterly dividends on our mandatory convertible preferred stock on February 1, May 1, August 1, and November 1 of each year, if declared by our Board of Directors. For the three months ended March 31, 2017 and 2016, we paid $5 million in dividends on February 1, 2017 and 2016, respectively.
Stock Purchase Agreement-Terawatt
On February 24, 2016, Dynegy entered into the PIPE Stock Purchase Agreement with Terawatt, pursuant to which at the ENGIE Acquisition Closing Date, Dynegy issued to Terawatt 13,711,152 common shares for $150 million. Please read Note 3—Acquisitions and Divestitures for further discussion.
ECP Buyout
As noted in Note 3—Acquisitions and Divestitures, Dynegy paid the ECP Buyout Price to ECP. This payment is reflected as a reduction in additional paid-in capital in our unaudited consolidated balance sheet as of March 31, 2017.
Earnings (Loss) Per Share
Basic earnings (loss) per share is based on the weighted average number of common shares outstanding during the period. Diluted earnings (loss) is based on the weighted average number of common shares used for the basic earnings (loss) per share computation, adjusted for the incremental issuance of shares of common stock assuming (i) our stock options and warrants are exercised, (ii) our restricted stock units and performance stock units are fully vested under the treasury stock method, and (iii) our mandatory convertible preferred stock and the SPCs are converted into common stock under the if converted method. Please read Note 18—Capital Stock and Note 13—Tangible Equity Units in our Form 10-K for further discussion.
The following table reflects significant components of our weighted average shares outstanding used in the basic and diluted loss per share calculations for the three months ended March 31, 2017 and 2016:
 
 
Three Months Ended March 31,
(in millions)
 
2017
 
2016
Shares outstanding at the beginning of the period (1)
 
140

 
117

Weighted-average shares outstanding during the period of:
 
 
 
 
Shares issued under the PIPE Transaction
 
8

 

Basic weighted-average shares outstanding
 
148

 
117

Dilution from potentially dilutive shares (2)
 
19

 

Diluted weighted-average shares outstanding
 
167

 
117

_________________________________________
(1)
The minimum settlement amount of the TEUs, or 23,092,460 shares, are considered to be outstanding since the issuance date of June 21, 2016, and are included in the computation of basic earnings (loss) per share for the three months ended March 31, 2017. No such amounts were considered outstanding for the three months ended March 31, 2016. Please read Note 13—Tangible Equity Units in our Form 10-K for further discussion.
(2)
Shares included in the computation of diluted earnings (loss) per share for the three months ended March 31, 2017 consist of:    
5,425,700 additional shares upon settlement of the TEUs - which reflects the difference between the minimum settlement amount included in basic weighted-average shares outstanding and the maximum settlement amount (28,518,160 shares);
12,903,200 additional shares consisting of the maximum settlement amount of shares which can be converted from our outstanding mandatory convertible preferred stock; and
484,216 additional shares attributable to restricted stock units and performance stock units.
Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three months ended March 31, 2016.

28

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

For the three months ended March 31, 2017 and 2016, the following potentially dilutive securities were not included in the computation of diluted per share amounts because the effect would be anti-dilutive:
 
 
Three Months Ended March 31,
(in millions of shares)
 
2017
 
2016
Stock options
 
2.8

 
2.8

Restricted stock units
 

 
1.3

Performance stock units
 

 
1.2

2012 Warrants
 
15.6

 
15.6

2017 Warrants
 
8.7

 

Series A 5.375% mandatory convertible preferred stock
 

 
12.9

Total
 
27.1

 
33.8

Accumulated Other Comprehensive Income
Changes in accumulated other comprehensive income, net of tax, by component, are as follows:
 
 
Three Months Ended March 31,
(amounts in millions)
 
2017
 
2016
Beginning of period
 
$
21

 
$
19

Other comprehensive income before reclassifications:
 
 
 
 
Actuarial gain and plan amendments (net of tax of zero and zero, respectively)
 
15

 

Amounts reclassified from accumulated other comprehensive income:
 


 


Amortization of unrecognized prior service credit (net of tax of zero and zero, respectively) (1)
 
(2
)
 
(1
)
Net current period other comprehensive income (loss), net of tax
 
13

 
(1
)
End of period
 
$
34

 
$
18

__________________________________________
(1)
Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost (gain). Please read Note 15—Pension and Other Post-Employment Benefit Plans for further discussion.
Note 17—Condensed Consolidating Financial Information
Dynegy’s senior notes are guaranteed by certain of our wholly owned subsidiaries. Not all of Dynegy’s subsidiaries guaranteed the senior notes. The following condensed consolidating financial statements present the financial information of (i) Dynegy (“Parent”), which is the parent and issuer of the senior notes, on a stand-alone, unconsolidated basis, (ii) the guarantor subsidiaries of Dynegy, (iii) the non-guarantor subsidiaries of Dynegy, and (iv) the eliminations necessary to arrive at the information for Dynegy on a consolidated basis. The 100 percent owned subsidiary guarantors, jointly, severally, fully, and unconditionally, guarantee the payment obligations under the senior notes. Please read Note 12—Debt for further discussion.
These statements should be read in conjunction with the unaudited consolidated financial statements and notes thereto of Dynegy. The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. The inclusion of Dynegy’s subsidiaries as either guarantor subsidiaries or non-guarantor subsidiaries in the condensed consolidating financial information is determined as of the most recent balance sheet date presented. On February 2, 2017, upon Genco’s emergence from bankruptcy, IPH (excluding Electric Energy, Inc.) became a guarantor to the senior notes. Accordingly, condensed consolidating financial information previously reported has been retroactively adjusted to reflect the status of Dynegy’s subsidiaries as either guarantor subsidiaries or non-guarantor subsidiaries as of March 31, 2017.
For purposes of the unaudited condensed consolidating financial statements, a portion of our intercompany receivable, which we do not consider to be likely of settlement, has been classified as equity as of March 31, 2017 and December 31, 2016.

29

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Condensed Consolidating Balance Sheet as of March 31, 2017
(amounts in millions)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Current Assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
321

 
$
110

 
$
36

 
$

 
$
467

Accounts receivable, net
143

 
2,910

 
25

 
(2,684
)
 
394

Inventory

 
443

 
70

 

 
513

Other current assets
10

 
403

 
7

 
(103
)
 
317

Total Current Assets
474

 
3,866

 
138

 
(2,787
)
 
1,691

Property, plant and equipment, net

 
9,393

 
326

 

 
9,719

Investment in affiliates
16,557

 

 

 
(16,557
)
 

Investment in unconsolidated affiliates

 
149

 

 

 
149

Goodwill

 
799

 

 

 
799

Assets held-for-sale

 
451

 

 

 
451

Other long-term assets
7

 
229

 
35

 

 
271

Intercompany note receivable
96

 
8

 

 
(104
)
 

Total Assets
$
17,134

 
$
14,895

 
$
499

 
$
(19,448
)
 
$
13,080

Current Liabilities
 
 
 
 
 
 
 
 
 
Accounts payable
$
2,294

 
$
396

 
$
281

 
$
(2,684
)
 
$
287

Other current liabilities
286

 
306

 
128

 
(103
)
 
617

Total Current Liabilities
2,580

 
702

 
409

 
(2,787
)
 
904

Debt, long-term portion, net
8,930

 
239

 
31

 

 
9,200

Intercompany note payable
3,042

 
96

 

 
(3,138
)
 

Other long-term liabilities
156

 
355

 
51

 
(8
)
 
554

Total Liabilities
14,708

 
1,392

 
491

 
(5,933
)
 
10,658

Stockholders’ Equity
 
 
 
 
 
 
 
 
 
Dynegy Stockholders’ Equity
2,426

 
16,549

 
8

 
(16,557
)
 
2,426

Intercompany note receivable

 
(3,042
)
 

 
3,042

 

Total Dynegy Stockholders’ Equity
2,426

 
13,507

 
8

 
(13,515
)
 
2,426

Noncontrolling interest

 
(4
)
 

 

 
(4
)
Total Equity
2,426

 
13,503

 
8

 
(13,515
)
 
2,422

Total Liabilities and Equity
$
17,134

 
$
14,895

 
$
499

 
$
(19,448
)
 
$
13,080


30

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Condensed Consolidating Balance Sheet as of December 31, 2016
(amounts in millions)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Current Assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
1,529

 
$
221

 
$
26

 
$

 
$
1,776

Restricted cash
21

 
41

 

 

 
62

Accounts receivable, net
141

 
2,604

 
39

 
(2,398
)
 
386

Inventory

 
326

 
119

 

 
445

Other current assets
12

 
408

 
2

 
(104
)
 
318

Total Current Assets
1,703

 
3,600

 
186

 
(2,502
)
 
2,987

Property, plant and equipment, net

 
6,772

 
349

 

 
7,121

Investment in affiliates
12,175

 

 

 
(12,175
)
 

Restricted cash
2,000

 

 

 

 
2,000

Goodwill

 
799

 

 

 
799

Other long-term assets
2

 
109

 
35

 

 
146

Intercompany note receivable

 
8

 

 
(8
)
 

Total Assets
$
15,880

 
$
11,288

 
$
570

 
$
(14,685
)
 
$
13,053

Current Liabilities
 
 
 
 
 
 
 
 
 
Accounts payable
$
1,990

 
$
443

 
$
297

 
$
(2,398
)
 
$
332

Other current liabilities
143

 
377

 
168

 
(104
)
 
584

Total Current Liabilities
2,133

 
820

 
465

 
(2,502
)
 
916

Liabilities subject to compromise

 
832

 

 

 
832

Debt, long-term portion, net
8,531

 
216

 
31

 

 
8,778

Intercompany note payable
3,042

 

 

 
(3,042
)
 

Other long-term liabilities
132

 
313

 
51

 
(8
)
 
488

Total Liabilities
13,838

 
2,181

 
547

 
(5,552
)
 
11,014

Stockholders’ Equity
 
 
 
 
 
 
 
 
 
Dynegy Stockholders’ Equity
2,042

 
12,152

 
23

 
(12,175
)
 
2,042

Intercompany note receivable

 
(3,042
)
 

 
3,042

 

Total Dynegy Stockholders’ Equity
2,042

 
9,110

 
23

 
(9,133
)
 
2,042

Noncontrolling interest

 
(3
)
 

 

 
(3
)
Total Equity
2,042

 
9,107

 
23

 
(9,133
)
 
2,039

Total Liabilities and Equity
$
15,880

 
$
11,288

 
$
570

 
$
(14,685
)
 
$
13,053


31

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Condensed Consolidating Statements of Operations for the Three Months Ended March 31, 2017
(amounts in millions)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
1,139

 
$
161

 
$
(53
)
 
$
1,247

Cost of sales, excluding depreciation expense

 
(695
)
 
(115
)
 
53

 
(757
)
Gross margin

 
444

 
46

 

 
490

Operating and maintenance expense

 
(201
)
 
(31
)
 



(232
)
Depreciation expense

 
(176
)
 
(24
)
 

 
(200
)
Impairments

 
(20
)
 

 

 
(20
)
General and administrative expense
(6
)
 
(33
)
 
(1
)
 

 
(40
)
Acquisition and integration costs
(44
)
 
(1
)
 

 

 
(45
)
Other

 

 
(2
)
 

 
(2
)
Operating income (loss)
(50
)
 
13

 
(12
)
 

 
(49
)
Bankruptcy reorganization items
(15
)
 
498

 

 

 
483

Losses from unconsolidated investments

 
(1
)
 

 

 
(1
)
Equity in earnings from investments in affiliates
806

 

 

 
(806
)
 

Interest expense
(161
)
 
(6
)
 
(3
)
 
3

 
(167
)
Other income and expense, net
17

 
3

 

 
(3
)
 
17

Income (loss) before income taxes
597

 
507

 
(15
)
 
(806
)
 
283

Income tax benefit

 
313

 

 

 
313

Net income (loss)
597

 
820

 
(15
)
 
(806
)
 
596

Less: Net loss attributable to noncontrolling interest

 
(1
)
 

 

 
(1
)
Net income (loss) attributable to Dynegy Inc.
$
597

 
$
821

 
$
(15
)
 
$
(806
)
 
$
597


Condensed Consolidating Statements of Operations for the Three Months Ended March 31, 2016
(amounts in millions)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
984

 
$
139

 
$

 
$
1,123

Cost of sales, excluding depreciation expense

 
(472
)
 
(73
)
 

 
(545
)
Gross margin

 
512

 
66

 

 
578

Operating and maintenance expense

 
(190
)
 
(31
)
 



(221
)
Depreciation expense

 
(150
)
 
(21
)
 

 
(171
)
General and administrative expense
(2
)
 
(33
)
 
(2
)
 

 
(37
)
Acquisition and integration costs
(3
)
 
(1
)
 

 

 
(4
)
Operating income (loss)
(5
)
 
138

 
12

 

 
145

Earnings from unconsolidated investments

 
2

 

 

 
2

Equity in earnings from investments in affiliates
118

 

 

 
(118
)
 

Interest expense
(124
)
 
(18
)
 

 

 
(142
)
Other income and expense, net
1

 
2

 
(2
)
 

 
1

Income (loss) before income taxes
(10
)
 
124

 
10

 
(118
)
 
6

Income tax expense

 
(16
)
 

 

 
(16
)
Net income (loss) attributable to Dynegy Inc.
$
(10
)
 
$
108

 
$
10

 
$
(118
)
 
$
(10
)


32

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2017
(amounts in millions)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Net income (loss)
$
597

 
$
820

 
$
(15
)
 
$
(806
)
 
$
596

Other comprehensive income before reclassifications:
 
 
 
 
 
 
 
 
 
Actuarial gain and plan amendments, net of tax of zero
15

 

 

 

 
15

Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
 
 
 
 
Amortization of unrecognized prior service credit, net of tax of zero
(2
)
 

 

 

 
(2
)
Other comprehensive income, net of tax
13

 

 

 

 
13

Comprehensive income (loss)
610

 
820

 
(15
)
 
(806
)
 
609

Less: Comprehensive loss attributable to noncontrolling interest

 
(1
)
 

 

 
(1
)
Total comprehensive income (loss) attributable to Dynegy Inc.
$
610

 
$
821

 
$
(15
)
 
$
(806
)
 
$
610


Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2016
(amounts in millions)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Net income (loss)
$
(10
)
 
$
108

 
$
10

 
$
(118
)
 
$
(10
)
Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
 
 
 
 
Amortization of unrecognized prior service credit, net of tax of zero
(1
)
 

 

 

 
(1
)
Other comprehensive loss, net of tax
(1
)
 

 

 

 
(1
)
Comprehensive income (loss)
(11
)
 
108

 
10

 
(118
)
 
(11
)
Less: Comprehensive loss attributable to noncontrolling interest

 

 

 

 

Total comprehensive income (loss) attributable to Dynegy Inc.
$
(11
)
 
$
108

 
$
10

 
$
(118
)
 
$
(11
)

33

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Condensed Consolidating Statements of Cash Flows for the Three Months Ended March 31, 2017
(amounts in millions)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
(93
)
 
$
184

 
$
58

 
$

 
$
149

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
Capital expenditures

 
(28
)
 
(3
)
 

 
(31
)
Acquisitions, net of cash acquired
(3,259
)
 
(4
)
 

 

 
(3,263
)
Distributions from unconsolidated investments

 
2

 

 

 
2

Net intercompany transfers
254

 

 

 
(254
)
 

Net cash used in investing activities
(3,005
)
 
(30
)
 
(3
)
 
(254
)
 
(3,292
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
Proceeds from long-term borrowings, net of debt issuance costs
425

 

 

 

 
425

Repayments of borrowings
(231
)
 
(30
)
 
(38
)
 

 
(299
)
Proceeds from issuance of equity, net of issuance costs
150

 

 

 

 
150

Preferred stock dividends paid
(5
)
 

 

 

 
(5
)
Interest rate swap settlement payments
(4
)
 

 

 

 
(4
)
Acquisition of noncontrolling interest
(375
)
 

 

 

 
(375
)
Payments related to bankruptcy financing
(119
)
 

 

 

 
(119
)
Net intercompany transfers

 
(248
)
 
(6
)
 
254

 

Intercompany borrowings, net of repayments
29

 
(28
)
 
(1
)
 

 

Other financing
(1
)
 

 

 

 
(1
)
Net cash provided by (used in) financing activities
(131
)
 
(306
)
 
(45
)
 
254

 
(228
)
Net increase (decrease) in cash, cash equivalents and restricted cash
(3,229
)
 
(152
)
 
10

 

 
(3,371
)
Cash, cash equivalents, and restricted cash beginning of period
3,550

 
262

 
26

 

 
3,838

Cash, cash equivalents, and restricted cash end of period
$
321

 
$
110

 
$
36

 
$

 
$
467



34

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Condensed Consolidating Statements of Cash Flows for the Three Months Ended March 31, 2016
(amounts in millions)
 
Parent
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
$
(14
)
 
$
307

 
$
(44
)
 
$

 
$
249

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
Capital expenditures

 
(105
)
 
(20
)
 

 
(125
)
Distributions from unconsolidated investments

 
8

 

 

 
8

Net intercompany transfers
339

 

 

 
(339
)
 

Net cash provided by (used in) investing activities
339

 
(97
)
 
(20
)
 
(339
)
 
(117
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
Proceeds from long-term borrowings, net of debt issuance costs

 
198

 

 

 
198

Repayments of borrowings
(2
)
 
(3
)
 

 

 
(5
)
Preferred stock dividends paid
(5
)
 

 

 

 
(5
)
Interest rate swap settlement payments
(4
)
 

 

 

 
(4
)
Net intercompany transfers

 
(345
)
 
6

 
339

 

Other financing
(2
)
 

 

 

 
(2
)
Net cash provided by (used in) financing activities
(13
)
 
(150
)
 
6

 
339

 
182

Net increase (decrease) in cash, cash equivalents and restricted cash
312

 
60

 
(58
)
 

 
314

Cash, cash equivalents and restricted cash, beginning of period
327

 
133

 
84

 

 
544

Cash, cash equivalents and restricted cash, end of period
$
639

 
$
193

 
$
26

 
$

 
$
858

Note 18—Genco Chapter 11 Bankruptcy and Emergence
On December 9, 2016, Genco filed a petition (the “Bankruptcy Petition”) under title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On January 25, 2017, the Bankruptcy Court confirmed the Genco Plan and Genco emerged from bankruptcy on February 2, 2017. As a result, we eliminated $825 million of Genco senior notes and $7 million of accrued interest in exchange for:
On the Emergence Date, $113 million of cash, $182 million of new Dynegy seven year unsecured notes, and warrants (the “2017 Warrants”) to purchase up to 8.7 million shares of common stock with a fair value of $17 million.
On April 18, 2017, $3 million of cash, $3 million of new Dynegy seven-year unsecured notes, and 0.1 million 2017 Warrants with a fair value of less than $1 million.
The 2017 Warrants, which have an exercise price of $35 per share of common stock, have a seven-year term expiring on February 2, 2024 and are recorded as Other long-term liabilities in our consolidated balance sheet as of March 31, 2017.
Remaining holders of Genco senior notes have until July 17, 2017 (the 165th day after the Emergence Date) in order to exercise their rights to receive a distribution. As of March 31, 2017, we have accrued a liability of $28 million, comprised of $6 million for the April 18, 2017 distribution and $22 million for potential future distributions.

35

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

The following table summarizes the Company’s gain from the termination of the Genco senior notes, which is recognized in Bankruptcy reorganization items in our consolidated statement of operations for the three months ended March 31, 2017 (includes consideration for claims exchanged on April 18, 2017):
(amounts in millions)
 
 
Liabilities subject to compromise, which were terminated
 
$
832

Less:
 
 
Seven-year unsecured notes
 
185

Cash consideration
 
116

Accrual for future potential distributions
 
22

2017 Warrants, at fair value
 
17

Legal and consulting fees
 
9

Bankruptcy reorganization items
 
$
483

For income tax purposes, the income from cancellation of debt is excluded from taxable income in the current year and will instead reduce Genco’s tax attributes.
Note 19—Segment Information
We report the results of our operations in six segments: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO, (v) IPH, and (vi) CAISO. PJM also includes our Dynegy Energy Services retail business in Ohio and Pennsylvania. IPH also includes our Homefield Energy retail business in Illinois. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense, and income tax benefit (expense).    

36

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three months ended March 31, 2017 and 2016 is presented below:
Segment Data as of and for the Three Months Ended March 31, 2017
(amounts in millions)
 
PJM
 
NY/NE
 
ERCOT
 
MISO
 
IPH
 
CAISO
 
Other and
Eliminations
 
Total
Domestic:
 
 

 
 
 
 

 
 
 
 
 
 
 
 

 
 

Unaffiliated revenues
 
$
630

 
$
309

 
$
17

 
$
92

 
$
175

 
$
24

 
$

 
$
1,247

Intercompany and affiliate revenues
 
(8
)
 
1

 
(1
)
 
8

 

 

 

 

Total revenues
 
$
622

 
$
310

 
$
16

 
$
100

 
$
175

 
$
24

 
$

 
$
1,247

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation expense
 
$
(92
)
 
$
(62
)
 
$
(13
)
 
$
(7
)
 
$
(12
)
 
$
(12
)
 
$
(2
)
 
$
(200
)
Impairments
 
(20
)
 

 

 

 

 

 

 
(20
)
General and administrative expense
 

 

 

 

 

 

 
(40
)
 
(40
)
Acquisition and integration costs
 

 

 

 

 

 

 
(45
)
 
(45
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
86

 
$
(41
)
 
$
(28
)
 
$
17

 
$
18

 
$
(14
)
 
$
(87
)
 
$
(49
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bankruptcy reorganization items
 

 

 

 

 
498

 

 
(15
)
 
483

Losses from unconsolidated investments
 
(1
)
 

 

 

 

 

 

 
(1
)
Interest expense
 

 

 

 

 

 

 
(167
)
 
(167
)
Other income and expense, net
 

 

 

 

 
1

 

 
16

 
17

Income before income taxes
 
 

 
 
 
 

 
 
 
 
 
 
 
 

 
283

Income tax benefit
 

 

 

 

 

 

 
313

 
313

Net income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
596

Less: Net loss attributable to noncontrolling interest
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1
)
Net income attributable to Dynegy Inc.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$
597

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets—domestic
 
$
5,765

 
$
3,720

 
$
1,615

 
$
340

 
$
597

 
$
473

 
$
570

 
$
13,080

Investment in unconsolidated affiliate
 
$
72

 
$
77

 
$

 
$

 
$

 
$

 
$

 
$
149

Capital expenditures
 
$
(12
)
 
$
(6
)
 
$
(1
)
 
$
(1
)
 
$
(3
)
 
$
(3
)
 
$
(2
)
 
$
(28
)

37

DYNEGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the Interim Periods Ended March 31, 2017 and 2016

Segment Data as of and for the Three Months Ended March 31, 2016
(amounts in millions) 
 
PJM
 
NY/NE
 
MISO
 
IPH
 
CAISO
 
Other and
Eliminations
 
Total
Domestic:
 
 

 
 
 
 
 
 
 
 
 
 

 
 

Unaffiliated revenues
 
$
557

 
$
250

 
$
125

 
$
168

 
$
23

 
$

 
$
1,123

Intercompany revenues
 
5

 
(1
)
 
(3
)
 
(1
)
 

 

 

Total revenues
 
$
562

 
$
249

 
$
122

 
$
167

 
$
23

 
$

 
$
1,123

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation expense
 
$
(85
)
 
$
(57
)
 
$
(8
)
 
$
(9
)
 
$
(11
)
 
$
(1
)
 
$
(171
)
General and administrative expense
 

 

 

 

 

 
(37
)
 
(37
)
Acquisition and integration costs
 

 

 

 

 

 
(4
)
 
(4
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
177

 
$
(2
)
 
$
13

 
$
14

 
$
(14
)
 
$
(43
)
 
$
145

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings from unconsolidated investments
 
2

 

 

 

 

 

 
2

Interest expense
 

 

 

 

 

 
(142
)
 
(142
)
Other income and expense, net
 

 

 

 

 

 
1

 
1

Income before income taxes
 
 

 
 
 
 
 
 
 
 
 
 

 
6

Income tax expense
 

 

 

 

 

 
(16
)
 
(16
)
Net loss attributable to Dynegy Inc.
 
 
 
 
 
 
 
 
 
 
 
 
 
$
(10
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets—domestic
 
$
5,515

 
$
2,909

 
$
1,060

 
$
897

 
$
520

 
$
807

 
$
11,708

Investment in unconsolidated affiliate
 
$
185

 
$

 
$

 
$

 
$

 
$

 
$
185

Capital expenditures
 
$
(21
)
 
$
(22
)
 
$
(6
)
 
$
(11
)
 
$
(1
)
 
$
(4
)
 
$
(65
)

DYNEGY INC.
 
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
For the Interim Periods Ended March 31, 2017 and 2016
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 a holding company and conduct substantially all of our business operations through our subsidiaries.  We sell electric energy, capacity and ancillary services primarily on a wholesale basis from our power generation facilities. We also serve residential, municipal, commercial and industrial customers primarily in MISO and PJM through our Homefield Energy and Dynegy Energy Services retail businesses.  We currently own approximately 31,000 MW of generating capacity in twelve states and also provide retail electricity to residential, commercial, industrial, and municipal customers in Illinois, Ohio, and Pennsylvania. We report the results of our power generation business as six separate segments in our unaudited consolidated financial statements: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO (v) IPH and (vi) CAISO.

38


The charts below show our wholesale generation, retail load and Adjusted EBITDA contribution by fuel type during the first quarter.
generationbysegment.jpggenerationbyfueltype.jpgretailloada15.jpgaebitda.jpg
LIQUIDITY AND CAPITAL RESOURCES
Overview 
We maintain a strong focus on liquidity. We believe that we have adequate resources from a combination of our current liquidity position and cash expected to be generated from future operations to fund our liquidity and capital requirements as they become due.  Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, 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 collateral requirements, facility maintenance costs, and other costs such as payroll.
Since 2013, we have increased scale and shifted our portfolio mix, which was predominately coal-based, to a predominately gas-based portfolio, through four major acquisitions. We used a significant portion of our balance sheet capacity to finance these acquisitions. We are now focused on strengthening our balance sheet, managing debt maturities and improving our leverage profile through debt reduction primarily from operating cash flows, PRIDE initiatives and select asset sales.

39


Liquidity.  The following table summarizes our liquidity position at March 31, 2017 (amounts in millions):
Revolving facilities and LC capacity (1)
 
$
1,675

Less:
 
 
 Outstanding revolvers
 
(300
)
 Outstanding LCs (2)
 
(476
)
Revolving facilities and LC availability
 
899

Cash and cash equivalents
 
467

Total available liquidity
 
$
1,366

__________________________________________
(1)
Includes $1.545 billion in senior secured revolving credit facilities and $130 million related to LCs. Please read Note 12—Debt—Letter of Credit Facilities for further discussion.
(2)
Upon the closing of our pending transaction, AEP will return a previously issued LC totaling $58 million to Dynegy. Please read Note 10—Joint Ownership of Generating Facilities for further discussion.
Quarterly Liquidity Highlights:    
January 2017 - Amended credit agreement (Fourth Amendment) to increase revolver capacity by $45 million and to extend the maturity date on $450 million in revolver capacity to 2021, which was effective upon the ENGIE Acquisition Closing Date.
February 2017 - Amended credit agreement (Fifth Amendment) to increase the Tranche C Term Loan amount by $224 million and to reduce interest rate by 75 basis points, which was effective upon the ENGIE Acquisition Closing Date. This is expected to save Dynegy approximately $100 million in interest costs over the next seven years.
February 2017 - Entered into new $50 million LC facility, which was effective upon the ENGIE Acquisition Closing Date.
February 2017 - Genco emerged from bankruptcy and, as a result, we eliminated $825 million of Genco senior notes. We exchanged $757 million of the Genco senior notes for $113 million cash, $182 million in Dynegy senior notes and 8.7 million 2017 Warrants.
February 2017 - Closed the ENGIE Acquisition for a base purchase price of $3.3 billion in cash.
February 2017 - Paid the ECP Buyout Price of $375 million.
February 2017 - Issued 13,711,152 common shares to Terawatt Holdings, LP for $150 million.
March 2017 - Refinanced previously monetized capacity under our Forward Capacity Sales Agreement by 24 months by replacing our sale of cleared capacity for Planning Year 2017-2018 with a sale for Planning Year 2019-2020.
April 2017 - We exchanged $15 million of the Genco senior notes for $3 million cash, $3 million in Dynegy senior notes and 0.1 million 2017 Warrants.

40



Cash Flows
The following table presents net cash from operating, investing, and financing activities for the three months ended March 31, 2017 and 2016:
 
 
Three Months Ended March 31,
(amounts in millions)
 
2017
 
2016
Net cash provided by operating activities
 
$
149

 
$
249

Net cash used in investing activities
 
$
(3,292
)
 
$
(117
)
Net cash provided by (used in) financing activities
 
$
(228
)
 
$
182

Operating Activities
Changes in net cash provided by operating activities for the three months ended March 31, 2017 compared to March 31, 2016 were primarily due to:
 
 
(in millions)
Increase in cash provided by operation of our power generation facilities and retail operations
 
$
2

Increase in interest payments on our various debt agreements
 
(2
)
Increase in payments for acquisition-related costs
 
(35
)
Decrease in cash provided by changes in working capital and other
 
(65
)
 
 
$
(100
)
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 natural gas, coal, and fuel oil 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, legal, environmental, and regulatory requirements, and our ability to achieve the cost savings contemplated in our “PRIDE Energized” initiative.
Collateral Postings. We use a portion of our capital resources in the form of cash and LCs to satisfy counterparty collateral demands. The following table summarizes our collateral postings to third parties at March 31, 2017 and December 31, 2016:
(amounts in millions)
 
March 31, 2017
 
December 31, 2016
Cash (1)
 
$
103

 
$
124

LCs
 
476

 
382

Total
 
$
579

 
$
506

__________________________________________
(1)
Includes broker margin as well as other collateral postings included in Prepayments and other current assets in our unaudited consolidated balance sheets. At March 31, 2017 and December 31, 2016, $66 million and $54 million, respectively, of cash posted as collateral were netted against Liabilities from risk management activities in our unaudited consolidated balance sheets.
Collateral postings increased from December 31, 2016 to March 31, 2017 primarily due to entry in the ERCOT market as a result of the ENGIE Acquisition. The fair value of our derivatives collateralized by first priority liens included liabilities of $131 million and $136 million at March 31, 2017 and December 31, 2016, respectively.

41


Investing Activities 
Historical Investing Cash Flows. Changes in net cash used in investing activities for the three months ended March 31, 2017 compared to March 31, 2016 were primarily due to:
 
 
(in millions)
Cash paid, net of cash acquired for the ENGIE Acquisition
 
$
(3,263
)
Decrease in capital expenditures
 
94

Decrease in other investing activity
 
(6
)
 
 
$
(3,175
)
Capital Expenditures.  Our capital spending by reportable segment was as follows: 
 
 
Three Months Ended March 31,
 
 
Estimated Remaining
(amounts in millions)
 
2017
 
2016
 
 
2017
PJM
 
$
12

 
$
21

 
 
$
92

NY/NE
 
6

 
22

 
 
64

ERCOT
 
1

 

 
 
13

MISO
 
1

 
6

 
 
7

IPH
 
3

 
11

 
 
30

CAISO
 
3

 
1

 
 
31

Other
 
2

 
4

 
 
9

Total (1)(2)
 
$
28

 
$
65

 
 
$
246

____________________________________
(1)
Includes capitalized interest of zero and $4 million for the three months ended March 31, 2017 and 2016, respectively.
(2)
Excludes prepayments of long-term service agreements until such time that the work is performed.
Capital spending in our PJM, MISO, and IPH segments primarily consisted of environmental and maintenance capital projects. Capital spending in our NY/NE, ERCOT, and CAISO segments primarily consisted of only maintenance capital projects.
Future Investing Cash Flows. The expected capital expenditures for the remainder of 2017 are noted above. The capital budget is subject to revision as opportunities arise or circumstances change.
Financing Activities 
Historical Financing Cash Flows.  Changes in net cash provided by financing activities for the three months ended March 31, 2017 compared to the same period March 31, 2016 were primarily due to:
 
 
(in millions)
Increase in proceeds from long-term borrowings, net of issuance costs, primarily related to the draws on the Revolver, and the Tranche C-1 Term Loan
 
$
425

Proceeds from issuance of equity related to the PIPE Transaction in 2017
 
150

Proceeds related to the Forward Capacity Agreement in 2016
 
(198
)
Cash paid related to the ECP Buyout in 2017
 
(375
)
Cash paid related to the Genco Bankruptcy in 2017
 
(119
)
Increase in repayment of borrowings, primarily related to the Tranche B-2 Term Loan and Inventory Financing Agreements
 
(294
)
Other financing activity
 
1

 
 
$
(410
)

42


Future Financing Cash Flows. Our future cash flows from financing activities include:
Principal payments on our debt instruments and other financial obligations;
Periodic payments to settle our interest rate swap agreements; and
Dividend payments on our mandatory convertible preferred stock.
Financing Trigger Events.  Our debt instruments and certain of our other financial obligations include provisions, which, if not met, could require early payment, additional collateral support or similar actions.  The trigger events include the violation of covenants (including, in the case of the Credit Agreement under certain circumstances, the senior secured leverage ratio covenant discussed below), 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, acceleration of other financial obligations, and, in the case of the Credit Agreement, change of control provisions.  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.  Please read Note 12—Debt for further discussion.
Financial Covenants 
Credit Agreement. Our Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a financial covenant specifying required thresholds for our senior secured leverage ratio calculated on a rolling four quarters basis.  To the extent Dynegy uses 25 percent or more of its Revolving Facility, the Fourth Amendment of the Credit Agreement requires that Dynegy must be in compliance with the Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio (as defined in the Credit Agreement). The Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio is 4.00:1.00. We were in compliance with these covenants as of March 31, 2017.
Existing balances under our Forward Capacity Agreement, Inventory Financing Agreements, and Equipment Financing Agreements are excluded from Net Debt, as defined in the Credit Agreement.
Dividends. We have paid no cash dividends on our common stock and have no current intention of doing so. Any future determinations to pay cash dividends will be at the discretion of our Board of Directors, subject to applicable limitations under Delaware law, and will be dependent upon our results of operations, financial condition, contractual restrictions, and other factors deemed relevant by our Board of Directors.
We pay quarterly dividends on our mandatory convertible preferred stock on February 1, May 1, August 1, and November 1 of each year, if declared by our Board of Directors. For the three months ended March 31, 2017 and 2016, we paid $5 million in dividends on February 1, 2017 and February 1, 2016, respectively.
On April 3, 2017, our Board of Directors declared a dividend on our mandatory convertible preferred stock of $1.34 per share, or approximately $5 million in the aggregate. The dividend is for the period beginning on February 1, 2017 and ending on April 30, 2017. Such dividends were paid on May 1, 2017, to stockholders of record as of April 15, 2017.
Credit Ratings
Our credit rating status is currently “non-investment grade” and our current ratings are as follows:
 
 
Moody’s
 
S&P
Dynegy Inc.:
 
 
 
 
Corporate Family Rating
 
B2
 
B+
Senior Secured
 
Ba3
 
BB
Senior Unsecured
 
B3
 
B+
RESULTS OF OPERATIONS
Overview and Discussion of Comparability of Results 
In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the three months ended March 31, 2017 and 2016.  At the end of this section, we have included our business outlook for each segment.
We report the results of our power generation business primarily as six separate segments in our unaudited consolidated financial statements: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO, (v) IPH, and (vi) CAISO. Our consolidated financial results

43


also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). All references to hedging within this Form 10-Q relate to economic hedging activities as we do not elect hedge accounting.
We completed the ENGIE Acquisition on February 7, 2017; therefore, the results of our newly acquired plants within our PJM, NY/NE and ERCOT segments are included in our consolidated results since the acquisition date. Please read Note 3—Acquisitions and Divestitures—ENGIE Acquisition for further discussion.
Consolidated Summary Financial Information — Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016  
The following table provides summary financial data regarding our unaudited consolidated results of operations for the three months ended March 31, 2017 and 2016, respectively:
 
 
Three Months Ended March 31,
 
Favorable (Unfavorable) $ Change
(amounts in millions)
 
2017
 
2016
 
Revenues
 
 
 
 
 

Energy
 
$
1,021

 
$
820

 
$
201

Capacity
 
203

 
184

 
19

Mark-to-market income, net
 
14

 
112

 
(98
)
Contract amortization
 
(15
)
 
(17
)
 
2

Other
 
24

 
24

 

Total revenues
 
1,247

 
1,123

 
124

Cost of sales, excluding depreciation expense
 
(757
)
 
(545
)
 
(212
)
Gross margin
 
490

 
578

 
(88
)
Operating and maintenance expense
 
(232
)
 
(221
)
 
(11
)
Depreciation expense
 
(200
)
 
(171
)
 
(29
)
Impairments
 
(20
)
 

 
(20
)
General and administrative expense
 
(40
)
 
(37
)
 
(3
)
Acquisition and integration costs
 
(45
)
 
(4
)
 
(41
)
Other
 
(2
)
 

 
(2
)
Operating income (loss)
 
(49
)
 
145

 
(194
)
Bankruptcy reorganization items
 
483

 

 
483

Earnings (loss) from unconsolidated investments
 
(1
)
 
2

 
(3
)
Interest expense
 
(167
)
 
(142
)
 
(25
)
Other income and expense, net
 
17

 
1

 
16

Income before income taxes
 
283

 
6

 
277

Income tax benefit (expense)
 
313

 
(16
)
 
329

Net income (loss)
 
596

 
(10
)
 
606

Less: Net loss attributable to noncontrolling interest
 
(1
)
 

 
(1
)
Net income (loss) attributable to Dynegy Inc.
 
$
597

 
$
(10
)
 
$
607


44


The following tables provide summary financial data regarding our operating income (loss) by segment for the three months ended March 31, 2017 and 2016, respectively:
 
 
Three Months Ended March 31, 2017
(amounts in millions)
 
PJM
 
NY/NE
 
ERCOT
 
MISO
 
IPH
 
CAISO
 
Other
 
Total
Revenues
 
$
622

 
$
310

 
$
16

 
$
100

 
$
175

 
$
24

 
$

 
$
1,247

Cost of sales, excluding depreciation expense
 
(337
)
 
(239
)
 
(17
)
 
(50
)
 
(103
)
 
(11
)
 

 
(757
)
Gross margin
 
285

 
71

 
(1
)
 
50

 
72

 
13

 

 
490

Operating and maintenance expense
 
(87
)
 
(48
)
 
(14
)
 
(26
)
 
(42
)
 
(15
)
 

 
(232
)
Depreciation expense
 
(92
)
 
(62
)
 
(13
)
 
(7
)
 
(12
)
 
(12
)
 
(2
)
 
(200
)
Impairments
 
(20
)
 

 

 

 

 

 

 
(20
)
General and administrative expense
 

 

 

 

 

 

 
(40
)
 
(40
)
Acquisition and integration costs
 

 

 

 

 

 

 
(45
)
 
(45
)
Other
 

 
(2
)
 

 

 

 

 

 
(2
)
Operating income (loss)
 
$
86

 
$
(41
)
 
$
(28
)
 
$
17

 
$
18

 
$
(14
)
 
$
(87
)
 
$
(49
)

 
 
Three Months Ended March 31, 2016
(amounts in millions)
 
PJM
 
NY/NE
 
MISO
 
IPH
 
CAISO
 
Other
 
Total
Revenues
 
$
562

 
$
249

 
$
122

 
$
167

 
$
23

 
$

 
$
1,123

Cost of sales, excluding depreciation expense
 
(213
)
 
(154
)
 
(63
)
 
(99
)
 
(16
)
 

 
(545
)
Gross margin
 
349

 
95

 
59

 
68

 
7

 

 
578

Operating and maintenance expense
 
(87
)
 
(40
)
 
(38
)
 
(45
)
 
(10
)
 
(1
)
 
(221
)
Depreciation expense
 
(85
)
 
(57
)
 
(8
)
 
(9
)
 
(11
)
 
(1
)
 
(171
)
General and administrative expense
 

 

 

 

 

 
(37
)
 
(37
)
Acquisition and integration costs
 

 

 

 

 

 
(4
)
 
(4
)
Operating income (loss)
 
$
177

 
$
(2
)
 
$
13

 
$
14

 
$
(14
)
 
$
(43
)
 
$
145

Discussion of Consolidated Results of Operations
Revenues.  The following table summarizes the change in revenues by segment:
(amounts in millions)
 
PJM
 
NY/NE
 
ERCOT
 
MISO
 
IPH
 
CAISO
 
Total
Revenues, net of hedges, attributable to newly acquired ENGIE plants for the first quarter of 2017
 
$
38

 
$
23

 
$
16

 
$

 
$

 
$

 
$
77

Higher (lower) power prices
 
54

 
62

 

 
2

 
(9
)
 
4

 
113

Higher (lower) generation volumes (1)
 
19

 
19

 

 
(13
)
 
1

 
(11
)
 
15

Higher (lower) capacity revenues
 
(18
)
 
(4
)
 

 
1

 
17

 
2

 
(2
)
Change in MTM value of derivative transactions
 
(43
)
 
(39
)
 

 
(13
)
 
(2
)
 
6

 
(91
)
Lower (higher) contract amortization
 

 
(2
)
 

 

 
2

 
1

 
1

Other (2)
 
10

 
2

 

 
1

 
(1
)
 
(1
)
 
11

Total change in revenues
 
$
60

 
$
61

 
$
16

 
$
(22
)
 
$
8

 
$
1

 
$
124

 _______________________________________
(1)
Increase primarily due to lower outages, offsetting decrease primarily due to plant shutdowns at our MISO and CAISO segments.
(2)
Other primarily consists of ancillary, tolling, transmission and gas revenues.

45


Cost of Sales.  The following table summarizes the change in cost of sales by segment:
(amounts in millions)
 
PJM
 
NY/NE
 
ERCOT
 
MISO
 
IPH
 
CAISO
 
Total
Cost of sales attributable to newly acquired ENGIE plants for the first quarter of 2017
 
$
16

 
$
10

 
$
17

 
$

 
$

 
$

 
$
43

Higher (lower) prices
 
78

 
70

 

 
(1
)
 
(2
)
 
7

 
152

Higher (lower) generation volumes (1)
 
12

 
23

 

 
(12
)
 
10

 
(10
)
 
23

Higher (lower) transportation costs
 
1

 

 

 

 

 
(1
)
 

Lower (higher) contract amortization
 
10

 
(15
)
 

 

 
3

 

 
(2
)
Other (2)
 
7

 
(3
)
 

 

 
(7
)
 
(1
)
 
(4
)
Total change in cost of sales
 
$
124

 
$
85

 
$
17

 
$
(13
)
 
$
4

 
$
(5
)
 
$
212

 _______________________________________
(1)
Higher generation volumes primarily due to lower outages and increased run times at our PJM, NY/NE and IPH segments; offsetting decrease primarily due to plant shutdowns at our MISO and CAISO segments.
(2)
Other primarily consists of transmission expenses.
Operating and Maintenance Expense.  O&M expense increased by $11 million primarily due to the newly acquired ENGIE plants for the first quarter of 2017, partially offset by a decrease primarily due to plant shutdowns at our MISO segment.
Depreciation Expense.  Depreciation expense increased by $29 million primarily due to increases from the newly acquired ENGIE plants, additions, and changes in useful lives, offset by decreases due to impairments.
Impairments. Impairments increased by $20 million due to charges in 2017 at our PJM segment on our Killen facility. Please read Note 9—Property, Plant and Equipment for further discussion.
General and Administrative Expense.  General and administrative expense increased by $3 million primarily due to higher overhead associated with the ENGIE Acquisition and higher legal fees.
Acquisition and Integration Costs. Acquisition and integration costs increased by $41 million due to $31 million in advisory and consulting fees, and $10 million in severance, retention, and payroll costs related to the ENGIE Acquisition in 2017.
Bankruptcy Reorganization Items. Bankruptcy reorganization items increased by $483 million primarily due to the gain on extinguishment of debt and legal costs associated with the Genco bankruptcy reorganization. Please read Note 18—Genco Chapter 11 Bankruptcy and Emergence—Reorganization items for further discussion.
Interest Expense.  Interest expense increased by $25 million primarily due to interest on our Tranche C-1 Term Loan and 2025 Senior Notes. Please read Note 12—Debt for further discussion.
Other Income and Expense.  Other income and expense increased by $16 million primarily due to the change in fair value of our common stock warrants and interest income on the Tranche C Term Loan that was held in escrow.
Income Tax Benefit (Expense).  The net favorable change of $329 million was primarily due to a $317 million benefit associated with a partial release of our deferred tax asset valuation allowance during the three months ended March 31, 2017 as a result of the ENGIE Acquisition.
Net income (loss) attributable to Dynegy Inc. The $607 million increase was primarily due to (i) a $22 million loss attributable to newly acquired ENGIE plants in the first quarter of 2017, (ii) income from a $317 million deferred tax valuation allowance release in 2017, and (iii) a $483 million gain primarily due to extinguishment of debt associated with the Genco bankruptcy reorganization, partially offset by (i) $91 million in losses associated with our hedging transactions, (ii) $45 million in acquisition and integration costs related to the ENGIE Acquisition, and (iii) $20 million in impairment charges recorded in 2017.
Discussion of Adjusted EBITDA
Non-GAAP Measures. In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed with our GAAP results and the accompanying reconciliations to corresponding GAAP financial measures included in the tables below, may provide a more complete understanding of factors and trends affecting our business. These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are by definition an incomplete understanding of Dynegy and must be considered in conjunction with GAAP measures.

46


We believe that the non-GAAP measures disclosed in our filings are only useful as an additional tool to help management and investors make informed decisions about our financial and operating performance. By definition, non-GAAP measures do not give a full understanding of Dynegy; therefore, to be truly valuable, they must be used in conjunction with the comparable GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies’ non-GAAP financial measures having the same or similar names. We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.
EBITDA and Adjusted EBITDA. We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale of certain assets, (ii) the impacts of mark-to-market changes on derivatives related to our generation portfolio, as well as warrants, (iii) the impact of impairment charges, (iv) certain other costs such as those associated with acquisitions, (v) non-cash compensation expense, and (vi) other material or unusual items.
We believe EBITDA and Adjusted EBITDA provide meaningful representations of our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of our entire power generation fleet for the period presented; consequently, it excludes the impact of mark-to-market accounting, impairment charges and other items that could be considered “non-operating” or “non-core” in nature. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for our investors. In addition, many analysts, fund managers and other stakeholders who communicate with us typically request our financial results in an EBITDA and Adjusted EBITDA format.
As prescribed by the SEC, when EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss). Management does not analyze interest expense and income taxes on a segment level; therefore, the most directly comparable GAAP financial measure to EBITDA or Adjusted EBITDA when performance is discussed on a segment level is Operating income (loss). 

47


Adjusted EBITDA — Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016
The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended March 31, 2017:
 
 
Three Months Ended March 31, 2017
(amounts in millions)
 
PJM
 
NY/NE
 
ERCOT
 
MISO
 
IPH
 
CAISO
 
Other
 
Total
Net income attributable to Dynegy Inc.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$
597

Loss attributable to noncontrolling interest
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1
)
Income tax benefit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(313
)
Other income and expense, net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(17
)
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
167

Loss from unconsolidated investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1

Bankruptcy reorganization items
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(483
)
Operating income (loss)
 
$
86

 
$
(41
)
 
$
(28
)
 
$
17

 
$
18

 
$
(14
)
 
$
(87
)
 
$
(49
)
Depreciation and amortization expense
 
100

 
68

 
13

 
8

 
14

 
15

 
2

 
220

Bankruptcy reorganization items
 

 

 

 

 
498

 

 
(15
)
 
483

Loss from unconsolidated investments
 
(1
)
 

 

 

 

 

 

 
(1
)
Other income and expense, net
 

 

 

 

 
1

 

 
16

 
17

EBITDA
 
185

 
27

 
(15
)
 
25

 
531

 
1

 
(84
)
 
670

Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest
 
1

 

 

 

 

 

 

 
1

Acquisition, integration and restructuring costs
 

 

 

 

 

 

 
46

 
46

Bankruptcy reorganization items
 

 

 

 

 
(498
)
 

 
15

 
(483
)
Mark-to-market adjustments, including warrants
 
(15
)
 
15

 
6

 
(15
)
 
(1
)
 
(4
)
 
(12
)
 
(26
)
Impairments
 
20

 

 

 

 

 

 

 
20

Non-cash compensation expense
 

 

 

 

 

 

 
5

 
5

Other
 

 

 

 

 
(1
)
 

 
(2
)
 
(3
)
Adjusted EBITDA
 
$
191

 
$
42

 
$
(9
)
 
$
10

 
$
31

 
$
(3
)
 
$
(32
)
 
$
230



48


The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended March 31, 2016:
 
 
Three Months Ended March 31, 2016
(amounts in millions)
 
PJM
 
NY/NE
 
ERCOT
 
MISO
 
IPH
 
CAISO
 
Other
 
Total
Net loss attributable to Dynegy Inc.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$
(10
)
Income tax expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
16

Other income and expense, net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1
)
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
142

Earnings from unconsolidated investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(2
)
Operating income (loss)
 
$
177

 
$
(2
)
 
$

 
$
13

 
$
14

 
$
(14
)
 
$
(43
)
 
$
145

Depreciation and amortization expense
 
83

 
75

 

 
9

 
10

 
12

 
1

 
190

Earnings from unconsolidated investments
 
2

 

 

 

 

 

 

 
2

Other income and expense, net
 

 

 

 

 

 

 
1

 
1

EBITDA
 
262

 
73

 

 
22

 
24

 
(2
)
 
(41
)
 
338

Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest
 
3

 

 

 

 

 

 

 
3

Acquisition and integration costs
 

 

 

 

 

 

 
4

 
4

Mark-to-market adjustments, including warrants
 
(56
)
 
(20
)
 

 
(28
)
 
(3
)
 
2

 
(1
)
 
(106
)
Non-cash compensation expense
 

 

 

 

 

 

 
7

 
7

Other (1)
 

 

 

 
5

 

 

 

 
5

Adjusted EBITDA
 
$
209

 
$
53

 
$

 
$
(1
)
 
$
21

 
$

 
$
(31
)
 
$
251

__________________________________________
(1)
Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $5 million for the three months ended March 31, 2016. Adjusted EBITDA did not include this adjustment for the three months ended March 31, 2017.
Adjusted EBITDA decreased by $21 million. The newly acquired ENGIE plants contributed $15 million in the first quarter of 2017. The offsetting $36 million decrease was primarily driven by lower energy margin, net of hedges as a result of decreased spark spreads and higher gas costs at the PJM segment and decreased dark spreads at the NY/NE segment, both driven by mild weather. Please read Discussion of Segment Adjusted EBITDA for further information.

49


Discussion of Segment Adjusted EBITDA — Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016
PJM Segment
The following table provides summary financial data regarding our PJM segment results of operations for the three months ended March 31, 2017 and 2016, respectively:
 
 
Three Months Ended March 31,
 
Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)
 
2017
 
2016
 
Operating revenues
 
 

 
 
 
 

Energy
 
$
498

 
$
395

 
$
103

Capacity
 
107

 
111

 
(4
)
Mark-to-market income, net
 
15

 
56

 
(41
)
Contract amortization
 
(9
)
 
(10
)
 
1

Other
 
11

 
10

 
1

Total operating revenues
 
622

 
562

 
60

Operating costs
 
 
 
 
 
 
Cost of sales
 
(340
)
 
(226
)
 
(114
)
Contract amortization
 
3

 
13

 
(10
)
Total operating costs
 
(337
)
 
(213
)
 
(124
)
Gross margin
 
285

 
349

 
(64
)
Operating and maintenance expense
 
(87
)
 
(87
)
 

Depreciation expense
 
(92
)
 
(85
)
 
(7
)
Impairments
 
(20
)
 

 
(20
)
Operating income
 
86

 
177

 
(91
)
Depreciation and amortization expense
 
100

 
83

 
17

Earnings (loss) from unconsolidated investments
 
(1
)
 
2

 
(3
)
EBITDA
 
185

 
262

 
(77
)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments
 
1

 
3

 
(2
)
Mark-to-market adjustments
 
(15
)
 
(56
)
 
41

Impairments
 
20

 

 
20

Adjusted EBITDA (1)
 
$
191

 
$
209

 
$
(18
)
 
 
 
 
 
 
 
Million Megawatt Hours Generated (1)
 
13.4

 
13.0

 
0.4

IMA (1)(2):
 
 
 
 
 
 
Combined-Cycle Facilities
 
89
%
 
98
%
 
 
Coal-Fired Facilities
 
65
%
 
77
%
 
 
Average Capacity Factor (1)(3):
 
 
 
 
 
 
Combined-Cycle Facilities
 
68
%
 
83
%
 


Coal-Fired Facilities
 
60
%
 
43
%
 


CDDs (4)
 
2

 
2

 

HDDs (4)
 
2,226

 
2,449

 
(223
)
Average Market On-Peak Spark Spreads ($/MWh) (5):
 
 
 
 
 
 
PJM West
 
$
11.38

 
$
18.73

 
$
(7.35
)
AD Hub
 
$
12.63

 
$
19.81

 
$
(7.18
)
Average Market On-Peak Power Prices ($/MWh) (6):
 
 
 
 
 
 
PJM West
 
$
32.52

 
$
31.49

 
$
1.03

AD Hub
 
$
31.39

 
$
28.80

 
$
2.59

Average natural gas price—TetcoM3 ($/MMBtu) (7)
 
$
3.02

 
$
1.82

 
$
1.20


50


 __________________________________________
(1)
Adjusted EBITDA includes the activity of the assets acquired in the ENGIE Acquisition for our period of ownership. Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA includes such activity for March.
(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. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs.
(3)
Reflects actual production as a percentage of available capacity. The calculation excludes CTs.
(4)
Reflects CDDs or HDDs for the PJM Region based on National Oceanic and Atmospheric Association (“NOAA”) data.
(5)
Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.
(6)
Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized.
(7)
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
Operating income decreased by $91 million primarily due to the following:
 
 
(in millions)
Income attributable to newly acquired plants in the first quarter of 2017
 
$
13

Lower energy margin, net of hedges, primarily due to lower spark spreads as a result of mild winter weather and higher gas costs, partially offset by higher generation volumes due to lower outages
 
$
(15
)
Lower capacity revenues as a result of lower pricing
 
$
(18
)
Change in MTM value of derivative transactions
 
$
(43
)
Asset impairments
 
$
(20
)
Lower contract amortization
 
$
(10
)
Adjusted EBITDA decreased by $18 million primarily due to the following:
 
 
(in millions)
Contribution from newly acquired plants in the first quarter of 2017
 
$
16

Lower energy margin, net of hedges, due to the following:
 
 
Lower spark spreads as a result of mild winter weather and higher gas costs
 
$
(40
)
Higher generation volumes primarily due to lower outages
 
$
24

Lower capacity revenues as a result of lower pricing
 
$
(18
)

51


NY/NE Segment
The following table provides summary financial data regarding our NY/NE segment results of operations for the three months ended March 31, 2017 and 2016, respectively:
 
 
Three Months Ended March 31,
 
Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)
 
2017
 
2016
 
Operating revenues
 
 

 
 
 
 

Energy
 
$
273

 
$
171

 
$
102

Capacity
 
46

 
43

 
3

Mark-to-market income (loss), net
 
(15
)
 
27

 
(42
)
Contract amortization
 
(4
)
 
(2
)
 
(2
)
Other
 
10

 
10

 

Total operating revenues
 
310

 
249

 
61

Operating costs
 
 
 
 
 
 
Cost of sales
 
(238
)
 
(138
)
 
(100
)
Contract amortization
 
(1
)
 
(16
)
 
15

Total operating costs
 
(239
)
 
(154
)
 
(85
)
Gross margin
 
71

 
95

 
(24
)
Operating and maintenance expense
 
(48
)
 
(40
)
 
(8
)
Depreciation expense
 
(62
)
 
(57
)
 
(5
)
Other
 
(2
)
 

 
(2
)
Operating loss
 
(41
)
 
(2
)
 
(39
)
Depreciation and amortization expense
 
68

 
75

 
(7
)
EBITDA
 
27

 
73

 
(46
)
Mark-to-market adjustments
 
15

 
(20
)
 
35

Adjusted EBITDA (1)
 
$
42

 
$
53

 
$
(11
)
 
 
 
 
 
 
 
Million Megawatt Hours Generated (1)
 
4.7

 
3.9

 
0.8

IMA for Combined-Cycle Facilities (1)(2)
 
98
%
 
89
%
 
 
Average Capacity Factor for Combined-Cycle Facilities (1)(3)
 
37
%
 
40
%
 
 
CDDs (4)
 

 

 

HDDs (4)
 
2,772

 
2,719

 
53

Average Market On-Peak Spark Spreads ($/MWh) (5):
 
 
 
 
 
 
New York—Zone A
 
$
10.99

 
$
16.69

 
$
(5.70
)
Mass Hub
 
$
6.63

 
$
10.82

 
$
(4.19
)
Average Market On-Peak Power Prices ($/MWh) (6):
 
 
 
 
 
 
Mass Hub
 
$
37.76

 
$
33.85

 
$
3.91

Average natural gas price—Algonquin Citygates ($/MMBtu) (7)
 
$
4.45

 
$
3.29

 
$
1.16

__________________________________________
(1)
Adjusted EBITDA includes the activity of the assets acquired in the ENGIE Acquisition for our period of ownership. Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA includes such activity for March.
(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. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes our Brayton Point facility.
(3)
Reflects actual production as a percentage of available capacity. The calculation excludes our Brayton Point facility.
(4)
Reflects CDDs or HDDs for the ISO-NE Region based on NOAA data.
(5)
Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.

52


(6)
Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized.
(7)
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
Operating loss increased by $39 million primarily due to the following:
 
 
(in millions)
Loss attributable to newly acquired plants in the first quarter of 2017
 
$
(5
)
Lower energy margin, net of hedges, primarily due to lower dark spreads at Brayton Point as a result of mild winter weather, partially offset by higher generation volumes as a result of lower planned outages
 
$
(5
)
Lower capacity revenues as a result of lower pricing
 
$
(4
)
Change in MTM value of derivative transactions
 
$
(39
)
Lower contract amortization
 
$
13

Adjusted EBITDA decreased by $11 million primarily due to the following:
 
 
(in millions)
Contribution from newly acquired plants in the first quarter of 2017
 
$
8

Lower energy margin, net of hedges, due to the following:
 
 
Lower dark spreads at Brayton Point as a result of mild winter weather
 
$
(15
)
Higher generation volumes as a result of lower planned outages
 
$
3

Lower capacity revenues as a result of lower pricing
 
$
(4
)

53


ERCOT Segment 
The ERCOT segment includes the results of operations since the ENGIE Acquisition Closing Date. The following table provides summary financial data regarding our ERCOT segment for the three months ended March 31, 2017:
 
 
Three Months Ended March 31,
 
Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)
 
2017
 
2016
 
Operating revenues
 
 
 
 
 
 
Energy
 
$
22

 
$

 
NA

Mark-to-market loss, net
 
(6
)
 

 
NA

Other
 

 

 
NA

Total operating revenues
 
16

 

 
NA

Operating costs
 
 
 
 
 
 
Cost of sales
 
(17
)
 

 
NA

Total operating costs
 
(17
)
 

 
NA

Gross margin
 
(1
)
 

 
NA

Operating and maintenance expense
 
(14
)
 

 
NA

Depreciation expense
 
(13
)
 

 
NA

Operating loss
 
(28
)
 

 
NA

Depreciation and amortization expense
 
13

 

 
NA

EBITDA
 
(15
)
 

 
NA

Mark-to-market adjustments
 
6

 

 
NA

Adjusted EBITDA (1)
 
$
(9
)
 
$

 
NA

 
 
 
 
 
 
 
Million Megawatt Hours Generated (1)
 
0.6

 

 
NA

IMA (1)(2):
 
 
 
 
 
 
Combined-Cycle Facilities
 
97
%
 
%
 


Coal-Fired Facility
 
93
%
 
%
 
 
Average Capacity Factor (1)(3):
 
 
 
 
 
 
Combined-Cycle Facilities
 
9
%
 
%
 


Coal-Fired Facility
 
18
%
 
%
 
 
CDDs (4)
 
267

 
120

 
147

HDDs (4)
 
494

 
758

 
(264
)
Average Market On-Peak Spark Spreads ($/MWh) (5):
 
 
 
 
 
 
ERCOT North
 
$
4.11

 
$
6.65

 
$
(2.54
)
Average Market On-Peak Power Prices ($/MWh) (6):
 
 
 
 
 
 
ERCOT North
 
$
23.54

 
$
19.62

 
$
3.92

Average natural gas price—Waha Hub ($/MMBtu) (7)
 
$
2.78

 
$
1.85

 
$
0.93

 __________________________________________
(1)
Adjusted EBITDA includes the activity of the assets acquired in the ENGIE Acquisition for our period of ownership. Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA includes such activity for March only.
(2)
IMA is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs. 
(3)
Reflects actual production as a percentage of available capacity. The calculation excludes CTs.
(4)
Reflects CDDs or HDDs for the ERCOT Region based on NOAA data.
(5)
Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.
(6)
Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized.

54


(7)
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
Operating loss of $28 million primarily consisted of the following:
 
 
(in millions)
Energy margin
 
$
5

MTM loss
 
$
(6
)
O&M costs
 
$
(14
)
Depreciation expense
 
$
(13
)
Adjusted EBITDA was a loss of $9 million primarily related to the following:
 
 
(in millions)
Energy margin
 
$
5

O&M costs primarily due to planned outages
 
$
(14
)
The Adjusted EBITDA results above are reflective of ERCOT being a primarily summer-based cooling market. Due to this, outages are generally performed between March and April in preparation for summer months. During the first quarter, we had multiple planned outages.





55


MISO Segment
The following table provides summary financial data regarding our MISO segment results of operations for the three months ended March 31, 2017 and 2016, respectively:
 
 
Three Months Ended March 31,
 
Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)
 
2017
 
2016
 
Operating revenues
 
 

 
 
 
 

Energy
 
$
77

 
$
88

 
$
(11
)
Capacity
 
7

 
6

 
1

Mark-to-market income, net
 
15

 
28

 
(13
)
Other
 
1

 

 
1

Total operating revenues
 
100

 
122

 
(22
)
Operating costs
 
 
 
 
 
 
Cost of sales
 
(50
)
 
(63
)
 
13

Total operating costs
 
(50
)
 
(63
)
 
13

Gross margin
 
50

 
59

 
(9
)
Operating and maintenance expense
 
(26
)
 
(38
)
 
12

Depreciation expense
 
(7
)
 
(8
)
 
1

Operating income
 
17

 
13

 
4

Depreciation and amortization expense
 
8

 
9

 
(1
)
EBITDA
 
25

 
22

 
3

Mark-to-market adjustments
 
(15
)
 
(28
)
 
13

Other (1)
 

 
5

 
(5
)
Adjusted EBITDA
 
$
10

 
$
(1
)
 
$
11

 
 
 
 
 
 
 
Million Megawatt Hours Generated
 
2.7

 
3.3

 
(0.6
)
IMA for Coal-Fired Facilities (2)
 
89
%
 
89
%
 
 
Average Capacity Factor for Coal-Fired Facilities (3)
 
65
%
 
50
%
 
 
CDDs (4)
 
57

 
28

 
29

HDDs (4)
 
2,203

 
2,424

 
(221
)
Average Market On-Peak Power Prices ($/MWh) (5):
 
 
 
 
 
 
Indiana (Indy Hub)
 
$
32.65

 
$
25.61

 
$
7.04

Commonwealth Edison (NI Hub)
 
$
30.27

 
$
27.34

 
$
2.93

 __________________________________________
(1)
Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $5 million for the three months ended March 31, 2016. Adjusted EBITDA did not include this adjustment for the three months ended March 31, 2017.
(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. The 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 CDDs or HDDs for the MISO Region based on NOAA data.
(5)
Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized.

56


Operating income increased by $4 million primarily due to the following:
 
 
(in millions)
Higher energy margin, net of hedges, primarily due to higher realized power prices driven by an increase in natural gas prices
 
$
3

Higher capacity revenue primarily due to higher volumes partially offset by lower pricing
 
$
1

Change in MTM value of derivative transactions
 
$
(13
)
Lower O&M costs due to shutdowns in 2016
 
$
12

Adjusted EBITDA increased by $11 million primarily due to the following:
 
 
(in millions)
Higher energy margin, net of hedges, primarily due to higher realized power prices driven by an increase in natural gas prices
 
$
3

Higher capacity revenue primarily due to higher volumes partially offset by lower pricing
 
$
1

Lower O&M costs due to shutdowns in 2016
 
$
7


57


IPH Segment
The following table provides summary financial data regarding our IPH segment results of operations for the three months ended March 31, 2017 and 2016, respectively:
 
 
Three Months Ended March 31,
 
Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)
 
2017
 
2016
 
Operating revenues
 
 
 
 
 
 
Energy
 
$
137

 
$
145

 
$
(8
)
Capacity
 
39

 
22

 
17

Mark-to-market income, net
 
1

 
3

 
(2
)
Contract amortization
 
(2
)
 
(4
)
 
2

Other
 

 
1

 
(1
)
Total operating revenues
 
175

 
167

 
8

Operating costs
 
 
 
 
 
 
Cost of sales
 
(105
)
 
(104
)
 
(1
)
Contract amortization
 
2

 
5

 
(3
)
Total operating costs
 
(103
)
 
(99
)
 
(4
)
Gross margin
 
72

 
68

 
4

Operating and maintenance expense
 
(42
)
 
(45
)
 
3

Depreciation expense
 
(12
)
 
(9
)
 
(3
)
Operating income
 
18

 
14

 
4

Depreciation and amortization expense
 
14

 
10

 
4

Bankruptcy reorganization items
 
498

 

 
498

Other income and expense, net
 
1

 

 
1

EBITDA
 
531

 
24

 
507

Bankruptcy reorganization items
 
(498
)
 

 
(498
)
Mark-to-market adjustments
 
(1
)
 
(3
)
 
2

Other
 
(1
)
 

 
(1
)
Adjusted EBITDA
 
$
31

 
$
21

 
$
10

 
 
 
 
 
 
 
Million Megawatt Hours Generated
 
3.8

 
3.3

 
0.5

IMA for IPH Facilities (1)
 
86
%
 
86
%
 
 
Average Capacity Factor for IPH Facilities (2)
 
52
%
 
39
%
 
 
CDDs (3)
 
57

 
28

 
29

HDDs (3)
 
2,203

 
2,424

 
(221
)
Average Market On-Peak Power Prices ($/MWh) (4):
 
 
 
 
 
 
Indiana (Indy Hub)
 
$
32.65

 
$
25.61

 
$
7.04

Commonwealth Edison (NI Hub)
 
$
30.27

 
$
27.34

 
$
2.93

 ________________________________________
(1)
IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs.  
(2)
Reflects actual production as a percentage of available capacity. The calculation excludes CTs.
(3)
Reflects CDDs or HDDs for the MISO Region based on NOAA data.
(4)
Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized.

58


Operating income increased by $4 million primarily due to the following:
 
 
(in millions)
Lower energy margin, net of hedges, primarily due to lower power prices due to transmission congestion, offset by higher generation due to fewer planned outages
 
$
(8
)
Higher capacity revenues due to higher price and volume
 
$
17

Change in MTM value of derivative transactions
 
$
(2
)
Depreciation
 
$
(3
)
Adjusted EBITDA increased by $10 million primarily due to the following:
 
 
(in millions)
Lower energy margin, net of hedges due to the following:
 

Lower power prices primarily due to transmission congestion
 
$
(13
)
Higher generation due to fewer planned outages
 
$
5

Higher capacity revenues due to higher price and volume
 
$
17

CAISO Segment 
The following table provides summary financial data regarding our CAISO segment results of operations for the three months ended March 31, 2017 and 2016, respectively:
 
 
Three Months Ended March 31,
 
Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)
 
2017
 
2016
 
Operating revenues
 
 
 
 
 
 
Energy
 
$
14

 
$
21

 
$
(7
)
Capacity
 
4

 
2

 
2

Mark-to-market income (loss), net
 
4

 
(2
)
 
6

Contract amortization
 

 
(1
)
 
1

Other
 
2

 
3

 
(1
)
Total operating revenues
 
24

 
23

 
1

Operating costs
 
 
 
 
 
 
Cost of sales
 
(11
)
 
(16
)
 
5

Total operating costs
 
(11
)
 
(16
)
 
5

Gross margin
 
13

 
7

 
6

Operating and maintenance expense
 
(15
)
 
(10
)
 
(5
)
Depreciation expense
 
(12
)
 
(11
)
 
(1
)
Operating loss
 
(14
)
 
(14
)
 

Depreciation and amortization expense
 
15

 
12

 
3

EBITDA
 
1

 
(2
)
 
3

Mark-to-market adjustments
 
(4
)
 
2

 
(6
)
Adjusted EBITDA
 
$
(3
)
 
$

 
$
(3
)
 
 
 
 
 
 
 
Million Megawatt Hours Generated
 
0.3

 
0.7

 
(0.4
)
IMA for Combined-Cycle Facilities (1)
 
95
%
 
99
%
 
 
Average Capacity Factor for Combined-Cycle Facilities (2)
 
14
%
 
29
%
 
 
CDDs (3)
 
25

 
44

 
(19
)
HDDs (3)
 
717

 
594

 
123

Average Market On-Peak Spark Spreads ($/MWh) (4):
 
 
 
 
 
 
North of Path 15 (NP 15)
 
$
8.34

 
$
10.71

 
$
(2.37
)
Average natural gas price—PG&E Citygate ($/MMBtu) (5)
 
$
3.34

 
$
2.20

 
$
1.14


59


 __________________________________________
(1)
IMA is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs. 
(2)
Reflects actual production as a percentage of available capacity. The calculation excludes CTs.
(3)
Reflects CDDs or HDDs for the CAISO Region based on NOAA data.
(4)
Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.
(5)
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
Operating loss was unchanged from 2016 but was impacted by the following:
 
 
(in millions)
Lower energy margin, net of hedges, primarily due to lower generation volumes as a result of higher competing hydroelectric generation
 
$
(3
)
Higher capacity revenues due to higher contracted volumes
 
$
2

Change in MTM value of derivative transactions
 
$
6

Higher O&M costs primarily due to planned outages and additions to AROs
 
$
(5
)
Adjusted EBITDA decreased by $3 million primarily due to the following:
 
 
(in millions)
Lower energy margin, net of hedges, primarily due to lower generation volumes as a result of higher competing hydroelectric generation
 
$
(3
)
Higher capacity revenues due to higher contracted volumes
 
$
2

Higher O&M costs associated with planned outages
 
$
(1
)
Outlook
We expect that our future financial results will continue to be impacted by market structure and prices for electric energy, capacity, and ancillary services, including pricing at our plant locations relative to pricing at their respective trading hubs, the volatility of fuel and electricity prices, transportation and transmission logistics, weather conditions, and the availability of our plants. Further, there is a trend toward greater environmental regulation of all aspects of our business. As this trend continues, it is possible that we will experience additional costs related to water, air, and coal ash regulations.
Certain states (Illinois and New York) in our markets have passed legislation or orders whereby those states will subsidize certain nuclear energy producers. We believe that these subsidies will adversely affect the energy and capacity markets by artificially suppressing prices. As a result, we are currently a party to lawsuits in Illinois and New York challenging these subsidy programs. Other states including Connecticut, New Jersey and Pennsylvania are also considering similar nuclear subsidy programs. Please read Environmental and Regulatory Matters below for further discussion.
The portions of our generation volumes sold, coal requirements contracted, coal requirements priced, and coal transportation requirements contracted, by segment, are discussed below. We look to procure and price additional coal and coal transportation opportunistically. For our gas-fired fleet, we hedge price risk by selling forward spark spreads which involves purchasing the required amount of natural gas at the same time as we sell power. We expect to continue our hedging program for energy over a one- to three-year period using various instruments, including retail sales in our PJM and IPH segments, and in accordance with our risk management policy.
Since 2013, we have increased scale and shifted our portfolio mix, which was predominately coal-based, to a predominately gas-based portfolio, through four major acquisitions. We used a significant portion of our balance sheet capacity to finance these acquisitions. We are now focused on strengthening our balance sheet, managing debt maturities and improving our leverage profile through debt reduction primarily from operating cash flows, PRIDE initiatives and select asset sales.

60


Our Operating Segments
PJM Segment. The PJM segment is comprised of 23 power generation facilities located within the PJM region, with a total generating capacity of 13,510 MW. We have recently announced the planned retirements of our jointly owned Stuart and Killen facilities by mid-2018.
In PJM, we are installing a total of 308 MW of uprates, which will be accomplished primarily through upgrades to the hot gas path components of our combined-cycle gas turbines and one peaking facility.  The uprates started in the fall of 2015 and are expected to be completed in the spring of 2018.
PJM introduced its new Capacity Performance (“CP”) product beginning with the Planning Year 2016-2017 capacity auction. CP resources must be capable of sustainable, predictable operation that allows them to be available to provide energy and reserves during performance assessment hours throughout the Delivery Year. Beginning in Planning Year 2018-2019, PJM introduced the Base product, which, alongside CP, replaced the legacy capacity product. Base capacity resources are those capacity resources that are not capable of sustained, predictable operation throughout the entire delivery year, but are capable of providing energy and reserves during hot weather operations. They are subject to non-performance charges assessed during emergency conditions, from June through September.
We use our retail business to hedge a portion of the energy output from our facilities. Our portfolio beyond 2018 is primarily open to benefit from possible future power market pricing improvements.
The following table reflects our hedging activities as of April 12, 2017:
 
 
2017
 
2018
 
2019 to 2021
Generation volumes hedged
 
92%
 
51%
 
7%
Coal requirements contracted (1)
 
80%
 
73%
 
15%
Coal requirements priced (1)
 
80%
 
73%
 
4%
Coal transportation requirements contracted (1)
 
100%
 
100%
 
100%
__________________________________________
(1)
Excludes non-operated jointly-owned generating units.
PJM Capacity Market. The most recent Reliability Pricing Model auction results for the zones in which our assets are located, are as follows for each Planning Year:
 
 
2016-2017
 
2017-2018
 
2018-2019
 
2019-2020
(price per MW-day)
 
Legacy Capacity
 
CP
 
Legacy Capacity
 
CP
 
Base
 
CP
 
Base
 
CP
RTO zone
 
$
59.37

 
$
134.00

 
$
120.00

 
$
151.50

 
$
149.98

 
$
164.77

 
$
80.00

 
$
100.00

MAAC zone
 
$
119.13

 
$
134.00

 
$
120.00

 
$
151.50

 
$
149.98

 
$
164.77

 
$
80.00

 
$
100.00

EMAAC zone
 
$
119.13

 
$
134.00

 
$
120.00

 
$
151.50

 
$
210.63

 
$
225.42

 
$
99.77

 
$
119.77

COMED zone
 
$
59.37

 
$
134.00

 
$
120.00

 
$
151.50

 
$
200.21

 
$
215.00

 
$
182.77

 
$
202.77

ATSI zone
 
$
114.23

 
$
134.00

 
$
120.00

 
$
151.50

 
$
149.98

 
$
164.77

 
$
80.00

 
$
100.00

PPL zone
 
$
119.13

 
$
134.00

 
$
120.00

 
$
151.50

 
$
75.00

 
$
164.77

 
$
80.00

 
$
100.00

Our capacity sales, net of purchases, aggregated by Planning Year and capacity type through Planning Year 2019-2020, are as follows:
 
 
2016-2017
 
2017-2018
 
2018-2019
 
2019-2020
Legacy/Base auction capacity sold, net (MW)
 
4,123
 
3,569
 
2,172
 
1,722
CP auction capacity sold, net (MW)
 
6,703
 
7,859
 
8,526
 
9,046
Bilateral capacity sold, net (MW)
 
85
 
2
 
295
 
200
Total segment capacity sold, net (MW)
 
10,911
 
11,430
 
10,993
 
10,968
Average price per MW-day
 
$120.35
 
$143.33
 
$179.06
 
$128.85
Our Kendall facility has one tolling agreement for 85 MW that expires in 2017. Effective as of the closing of the ENGIE Acquisition, we acquired a 50% non-operating ownership interest in the Sayreville facility.

61


NY/NE Segment. The NY/NE segment is comprised of 11 power generation facilities located within the ISO-NE (5,331 MW) and NYISO (1,212 MW) regions, totaling 6,543 MW of electric generating capacity.
In New York, we completed uprate installations which are expected to result in 35 MW of additional summer capacity and 79 MW of additional winter capacity. In addition to the benefit of incremental output, both blocks have experienced improved efficiency as a result of the uprates.
In New England, at our Lake Road and Milford-Connecticut facilities, we cleared 70 MW of new uprates in FCA-10, at a capacity rate of $7.03 per kW-month for seven years beginning with Planning Year 2019-2020 and extending through Planning Year 2025-2026. For FCA-11, we cleared a total of 34 MW of uprates at Lake Road and Casco Bay that did not qualify for a seven-year rate lock. Milford-Massachusetts cleared an incremental 53 MW of new capacity in FCA-11 that qualified the entire plant for a seven-year rate lock. Milford-Massachusetts will receive the FCA-11 clearing price of $5.30 per kW-month for 202 MW through Planning Year 2026-2027.
On February 2, 2017, FERC issued an order accepting the December 27, 2016 Compliance Filing of Atlas Power Finance, LLC, Dynegy, and ECP (collectively, “Applicants”), which proposed mitigation measures in response to market power concerns identified by FERC in its December 22, 2016 order conditionally authorizing the ENGIE Acquisition. In this order, FERC accepted, among other commitments, Applicants’ proposal to divest at least 224 MW in the Southeast New England capacity zone in ISO-NE, and Applicants’ commitment to execute agreements to sell the divested capacity by August 7, 2017. Our Brayton Point facility is expected to be retired in ISO-NE in June 2017.
The following table reflects our hedging activities as of April 12, 2017:
 
 
2017
 
2018
 
2019 to 2021
Generation volumes hedged (1)
 
91%
 
23%
 
5%
__________________________________________
(1)
Excludes our Brayton Point facility and volumes subject to tolling agreements.
NYISO Capacity Market. We have approximately 1,212 MW of power generation in NYISO. The most recent seasonal auction results for NYISO's Rest-of-State zones, in which the capacity for our Independence plant clears, are as follows for each planning period:
 
 
Winter 2016-2017
 
Summer 2017
Price per kW-month
 
$0.75
 
$3.00
Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of Independence’s capacity through bilateral trades. Our capacity sales, aggregated by season through Summer 2020, are as follows:
 
 
Winter 2016-2017
 
Summer 2017
 
Winter 2017-2018
 
Summer 2018
 
Winter 2018-2019
 
Summer 2019
 
Winter 2019-2020
 
Summer 2020
Auction capacity sold (MW)
 
396
 
47
 
 
 
 
 
 
Bilateral capacity sold (MW)
 
775
 
868
 
780
 
620
 
330
 
255
 
118
 
50
Total capacity sold (MW)
 
1,171
 
915
 
780
 
620
 
330
 
255
 
118
 
50
Average price per kW-month
 
$1.95
 
$3.41
 
$2.48
 
$3.66
 
$3.32
 
$3.39
 
$3.43
 
$3.45
ISO-NE Capacity Market. We have approximately 5,331 MW of power generation in ISO-NE. The most recent FCA results for ISO-NE Rest-of-Pool, in which most of our assets are located, are as follows for each Planning Year:
 
 
2016-2017
 
2017-2018
 
2018-2019
 
2019-2020
 
2020-2021
Price per kW-month
 
$3.15
 
$7.03
 
$9.55
 
$7.03
 
$5.30
On February 6, 2017, ISO-NE conducted the capacity auction for Planning Year 2020-2021 (FCA-11). In this auction, Rest-of-Pool cleared at $5.30 per kW-month. Performance incentive rules will go into effect for Planning Year 2018-2019, having the potential to increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level. Dynegy continues to market and pursue longer term multi-year capacity transactions that extend past FCA-11.

62


Our capacity sales, aggregated by Planning Year through Planning Year 2020-2021, are as follows:
 
 
2016-2017
 
2017-2018
 
2018-2019
 
2019-2020
 
2020-2021
Auction capacity sold (MW)
 
3,968
 
3,433
 
3,471
 
3,500
 
3,595
Bilateral capacity sold (MW)
 
199
 
148
 
91
 
44
 
Total capacity sold (MW)
 
4,167
 
3,581
 
3,562
 
3,544
 
3,595
Average price per kW-month
 
$3.19
 
$6.98
 
$10.08
 
$7.02
 
$5.38
ERCOT Segment. The ERCOT segment is comprised of six power generation facilities located within the ERCOT region, with a total generating capacity of 4,696 MW.
The following table reflects our hedging activities as of April 12, 2017:
 
 
2017
 
2018
 
2019 to 2021
Generation volumes hedged
 
56%
 
50%
 
3%
Coal requirements contracted
 
100%
 
—%
 
—%
Coal requirements priced
 
100%
 
—%
 
—%
Coal transportation requirements contracted
 
100%
 
100%
 
—%
ERCOT Market. In addition to the energy and fuel hedges summarized in the table above we also hedge using the forward sale of ancillary services.
MISO and IPH Segments.
MISO Segment. The MISO segment is comprised of three power generation facilities located within the MISO region, with a total generating capacity of 1,913 MW. On June 9, 2016, Dynegy announced that Hennepin will receive firm transmission service for a majority of the facility into the PJM control area beginning with Planning Year 2017-2018.  Beginning June 1, 2017, Hennepin will pseudo-tie and offer energy and capacity for 260 MW, or 14 percent of our current MISO capacity and energy, into PJM.  Hennepin’s remaining volume of approximately 34 MW will continue to be offered into MISO.
Dynegy’s portfolio beyond 2018 is primarily open to benefit from possible future power market pricing improvements. The following table reflects our hedging activities as of April 12, 2017:
 
 
2017
 
2018
 
2019 to 2021
Generation volumes hedged (1)
 
81%
 
49%
 
7%
Coal requirements contracted
 
100%
 
86%
 
56%
Coal requirements priced
 
100%
 
86%
 
—%
Coal transportation requirements contracted
 
100%
 
98%
 
96%
__________________________________________
(1)
Excludes Baldwin Unit 1 starting October 2018.
IPH Segment. The IPH segment is comprised of five power generation facilities, totaling 3,563 MW and primarily operates in MISO. Joppa, which is within the Electric Energy, Inc. control area, is interconnected to Tennessee Valley Authority and Louisville Gas and Electric Company, but primarily sells its capacity and energy to MISO. We currently offer a portion of our IPH segment generating capacity and energy into PJM. As of June 1, 2016, our Coffeen, Duck Creek, E.D. Edwards, and Newton facilities have 937 MW, or 26 percent of IPH’s current capacity and energy, electrically tied into PJM through pseudo-tie arrangements. Additionally, IPH has secured firm transmission beginning June 1, 2017 to export 240 MW into PJM from our Joppa facility.
IPH will continue to use our retail business to hedge a portion of the output from our IPH facilities. The retail hedges are well correlated to our facilities due to the close proximity of the hedge and through participation in FTR markets.

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The following table reflects our hedging activities as of April 12, 2017:
 
 
2017
 
2018
 
2019 to 2021
Generation volumes hedged
 
83%
 
47%
 
23%
Coal requirements contracted
 
98%
 
49%
 
27%
Coal requirements priced
 
75%
 
45%
 
—%
Coal transportation requirements contracted
 
100%
 
100%
 
100%
MISO Capacity Market. We have approximately 5,476 MW of power generation in MISO. This includes the 937 MW related to PJM pseudo-tie arrangements from the IPH fleet which began June 1, 2016. With Joppa’s export capability and Hennepin’s pseudo-tie arrangement that will begin on June 1, 2017, we will have approximately 1,437 MW expected to be sold in PJM for Planning Year 2020-2021. The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each Planning Year:
 
 
2016-2017
 
2017-2018
Price per MW-day
 
$72.00
 
$1.50
Our MISO and IPH segments cleared no incremental volumes, in excess of our retail load obligations, in the MISO Planning Year 2016-2017 or Planning Year 2017-2018 capacity auctions. MISO capacity sales through Planning Year 2020-2021 are as follows:
 
 
2016-2017
 
2017-2018
 
2018-2019
 
2019-2020
 
2020-2021
MISO Segment:
 
 
 
 
 
 
 
 
 
 
Bilateral capacity sold in MISO (MW)
 
1,011
 
1,075
 
242
 
185
 
185
Legacy/Base auction capacity sold in PJM (MW)
 
 
208
 
 
 
Total MISO segment capacity sold (MW)
 
1,011
 
1,283
 
242
 
185
 
185
Average price per kW-month
 
$2.75
 
$2.97
 
$2.68
 
$2.60
 
$2.71
 
 
 
 
 
 
 
 
 
 
 
IPH Segment:
 
 
 
 
 
 
 
 
 
 
Bilateral capacity sold in MISO (MW)
 
2,246
 
2,350
 
1,877
 
881
 
669
Legacy/Base auction capacity sold in PJM (MW)
 
50
 
365
 
 
260
 
CP auction capacity sold in PJM (MW)
 
730
 
472
 
835
 
356
 
Total IPH segment capacity sold (MW)
 
3,026
 
3,187
 
2,712
 
1,497
 
669
Average price per kW-month
 
$4.26
 
$4.43
 
$4.93
 
$4.00
 
$5.21
The results of the most recent MISO capacity auction further validate our strategy of right-sizing our MISO wholesale generation business to more closely match our retail business, export capacity, and wholesale origination effort. Despite a meaningful decline in the auction clearing price over the past two years, Dynegy has still been able to effectively monetize much of its available capacity at attractive prices.
CAISO Segment. The CAISO segment is comprised of two power generation facilities located within the CAISO region, with a total generating capacity of 1,185 MW.
In its 2015 Gas Transmission and Storage rate case, which sets gas transportation rates for 2015-2017, PG&E proposed revenue requirements and allocation proposals which would result in a significant increase in the rates for electric generators served by the local transmission system, including Moss Landing. Historically, after PG&E’s gas transportation rate structure was changed to unbundle the Backbone Transmission System (“BB”) rates, PG&E gas transmission and storage rate case settlements have included a bill credit for Moss Landing that effectively reduced the differential between rates for BB and local transmission system service, allowing the plant to compete against other power generators. Dynegy actively participated in the hearing process before the CPUC. However, on June 23, 2016, the CPUC approved a rate increase for local transmission customers, including Dynegy, of approximately 200 percent. Dynegy filed a request for rehearing of the CPUC’s unfavorable June 23, 2016 decision on August 1, 2016. The request for rehearing does not act as a stay on the rate increase, which went into effect on August 1, 2016. If Dynegy’s request for rehearing is denied, Dynegy will explore options for an appeal.

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The following table reflects our hedging activities as of April 12, 2017:
 
 
2017
 
2018
 
2019 to 2021
Generation volumes hedged
 
58%
 
—%
 
—%
CAISO Capacity Market. The CAISO capacity market is a bilateral market in which Load Serving Entities are required to procure sufficient resources to meet their peak load plus a 15 percent reserve margin.  We transact with investor owned utilities, municipalities, community choice aggregators, retail providers, and other marketers through Request for Offers solicitations, broker markets, and directly with bilateral transactions for both the Standard and Flexible RA capacity.
Our capacity sales, aggregated by calendar year for 2017 through 2019 for Moss Landing, are as follows:
 
 
Remainder of 2017
 
2018
 
2019
Bilateral capacity sold (Avg. MW)
 
766
 
400
 
850
We have also sold seasonal capacity for Moss Landing opportunistically. Our Oakland facility operated under a reliability must run (“RMR”) contract with the CAISO for 2016 and was given notice of extension for 2017.
Environmental and Regulatory Matters
Please read Item 1. Business—Environmental Matters in our Form 10-K for a detailed discussion of our environmental and regulatory matters.
State-based Subsidies
On August 1, 2016, the New York Public Service Commission (“NY PSC”) promulgated an Order adopting a Clean Energy Standard. The Order includes a program whereby the State will subsidize certain nuclear energy producers in New York through “zero emissions credits” (“ZECs”), which load serving entities will be required to buy, with the cost passed on to retail ratepayers. In October 2016, a group of generators including Dynegy, and our trade association, the Electric Power Supply Association, filed a lawsuit in the Southern District of New York challenging the NY PSC’s ruling on constitutional grounds. We cannot predict the outcome of that litigation, but if left unchecked, we believe these subsidies have already and will continue to adversely affect the energy and capacity markets in NYISO by artificially suppressing prices.
In December 2016, Illinois passed legislation, the Future Energy Jobs Act (“FEJA”) amending the Illinois Power Agency Act (“IPAA”) to create a ZEC program for Illinois nuclear generators. The FEJA amendments to the IPAA become effective on June 1, 2017, and unless enjoined or eliminated, the ZECs will result in an estimated $2.35 billion of payments over ten years to Exelon. In February 2017, a group of generators including Dynegy and our trade association, the Electric Power Supply Association, filed a lawsuit challenging the FEJA on constitutional grounds in the Northern District of Illinois, Eastern Division, followed by a Motion for Preliminary Injunction in March 2017. We cannot predict the outcome of that litigation, but if left unchecked, we believe these subsidies have already and will continue to adversely affect the energy and capacity markets in PJM and MISO.
The Clean Water Act
Effluent Limitation Guidelines. In April 2017, the EPA granted petitions requesting reconsideration of the Effluent Limitations Guideline (“ELG”) final rule. The EPA also administratively stayed and delayed the ELG rule’s compliance date deadlines pending judicial review. The EPA intends to decide, by fall 2017, which portions of the ELG rule, if any, that it will seek to have remanded for further rulemaking and to conduct notice and comment rulemaking during the reconsideration period to stay or amend the compliance deadlines for the ELG rule. A lawsuit has been filed challenging the administrative stay of the ELG rule.

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Our projected ELG compliance expenditures decreased by $56 million during the three months ended March 31, 2017 due to the announced shut down of Killen by its operator. In addition, we have continued to evaluate the timing of our ELG investments, and we have determined that, based on existing rules, most of the projects originally scheduled for 2017 and 2018 can be delayed by at least two years. Given the recent stay of the rule granted by the EPA, deferring this spend is also prudent to ensure that any investment made conforms to the ultimate rules which, at this point, are uncertain. As a result of these delays, $40 million of ELG investment originally expected in 2017 and $140 million in spend planned in 2018 have now been deferred to future years.
The majority of ELG compliance expenditures are expected to occur in the 2019-2023 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 March 31, 2017:
(amounts in millions)
 
Less than
1 Year
 
1 - 3 Years
 
3 - 5 Years
 
More than
5 Years
 
Total
ELG expenditures (1)
 
$
1

 
$
58

 
$
164

 
$
29

 
$
252

__________________________________________
(1)
Projections have not been adjusted to reflect the pending transactions with LS Power, AEP and AES. Please read Note 3—Acquisitions and Divestitures and Note 10—Joint Ownership of Generating Facilities for further discussion.
The Clean Air Act    
Coleto Creek Regional Haze. The EPA issued a federal implementation plan (“FIP”) in December 2015 for the State of Texas that imposed regional haze program reasonable progress requirements on numerous coal-fired EGUs. The FIP would require Coleto Creek to meet an SO2 emission limit of 0.04 lbs/MMBtu by February 2021, based on installation of a scrubber. Coleto Creek, other electricity generating companies and the State of Texas filed petitions for judicial review. In July 2016, the United States Court of Appeals for the Fifth Circuit stayed the FIP pending completion of judicial review. In March 2017, the court remanded the FIP to the EPA for reconsideration.
In January 2017, the EPA proposed a FIP for Texas that would impose Best Available Retrofit Technology (‘‘BART’’) emission limits for SO2 on numerous EGUs, including Coleto Creek. BART requirements for EGUs were not addressed in the EPA’s December 2015 regional haze FIP for Texas. The proposed FIP BART SO2 emissions limit for Coleto Creek is 0.04 lbs/MMBtu based on installation of a scrubber. Compliance would be required within five years from the effective date of a final rule.
A future requirement to install a scrubber at Coleto Creek as a result of either the reasonable progress FIP or proposed BART FIP, when final, could have a material adverse effect on Coleto Creek.
Coal Combustion Residuals
EPA CCR Rule. At this time, we estimate the cost of our compliance with the CCR rule will be approximately $301 million with the majority of the expenditures in the 2017-2023 timeframe. This estimate is reflected in our AROs.        
Coal Segment Groundwater. Please read Note 13—Commitments and Contingencies, Other Contingencies, Coal Segment Groundwater, for further discussion.
Climate Change
Clean Power Plan. In March 2017, the President of the United States issued Executive Order 13783 directing the EPA to review the Clean Power Plan, as well as the GHG new source performance standards, and, if appropriate, initiate proceedings to suspend, revise or rescind those rules.

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RISK MANAGEMENT DISCLOSURES 
The following table provides a reconciliation of the risk management data contained within our unaudited consolidated balance sheets on a net basis:
(amounts in millions)
 
As of and for the Three Months Ended March 31, 2017
Fair value of portfolio at December 31, 2016
 
$
6

Risk management gains recognized through the statement of operations in the period, net
 
38

Contracts realized or otherwise settled during the period
 
(18
)
Acquired derivatives
 
9

Change in collateral/margin netting
 
12

Fair value of portfolio at March 31, 2017
 
$
47

The net risk management asset of $47 million is the aggregate of the following line items in our unaudited consolidated balance sheets: Current Assets—Assets from risk management activities, Other Assets—Assets from risk management activities, Current Liabilities—Liabilities from risk management activities, and Other Liabilities—Liabilities from risk management activities. 
Risk Management Asset and Liability Disclosures.  The following table provides an assessment of net contract values by year as of March 31, 2017, based on our valuation methodology: 
Net Fair Value of Risk Management Portfolio 
(amounts in millions)
 
Total
 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
Market quotations (1)(2)
 
$

 
$
17

 
$
(12
)
 
$
(4
)
 
$
(1
)
 
$

 
$

Prices based on models (2)
 
(19
)
 
(18
)
 
(1
)
 

 

 

 

Total (3)
 
$
(19
)
 
$
(1
)
 
$
(13
)
 
$
(4
)
 
$
(1
)
 
$

 
$

 __________________________________________
(1)  Prices obtained from actively traded, liquid markets for commodities.
(2)  The market quotations category represents our transactions classified as Level 1 and Level 2. The prices based on models category represents transactions classified as Level 3.  Please read Note 5—Risk Management Activities, Derivatives and Financial Instruments for further discussion. 
(3)
Excludes $66 million of broker margin that has been netted against Risk management liabilities in our unaudited consolidated balance sheet. Please read Note 5—Risk Management Activities, Derivatives and Financial Instruments for further discussion.
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, fuel oil, and natural gas inventories and transportation thereof;

67


the effects of, or changes to the power and capacity procurement processes in the markets in which we operate;
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;
beliefs about the outcome of legal, administrative, legislative, and regulatory matters, including any impacts from the change in administration to these matters;
projected operating or financial results, including anticipated cash flows from operations, revenues, and profitability;
our focus on safety and our ability to operate our assets efficiently 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 and performance incentives in ISO-NE;
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;
efforts to secure retail sales and the ability to grow the retail business;
efforts to identify opportunities to reduce congestion and improve busbar power prices;
ability to mitigate impacts associated with expiring RMR and/or capacity contracts;
expectations regarding our compliance with the Credit Agreement, including collateral demands, interest expense, any applicable financial ratios, and other payments;
expectations regarding performance standards and capital and maintenance expenditures;
the timing and anticipated benefits to be achieved through our company-wide improvement programs, including our PRIDE initiative;
expectations regarding strengthening the balance sheet, managing debt maturities and improving Dynegy’s leverage profile;
expectations, timing and benefits of the AES and AEP transactions;
efforts to divest assets and the associated timing of such divestitures, and anticipated use of proceeds from such divestitures;
anticipated timing, outcome, and impact of expected retirements;
beliefs about the costs and scope of the ongoing demolition and site remediation efforts; and
expectations regarding the synergies and anticipated benefits of the ENGIE Acquisition.
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 Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our Form 10-K for a discussion of our exposure to commodity price variability and other market risks related to our net non-trading derivative assets and liabilities.  The following is a discussion of the more material of these risks and our relative exposures as of March 31, 2017.
Value at Risk (“VaR”).  The following table sets forth the aggregate daily VaR of the mark-to-market portion of our risk-management portfolio primarily associated with the PJM, NY/NE, ERCOT, MISO, and CAISO segments.  The VaR calculation does not include market risks associated with the accrual portion of the risk-management portfolio that is designated as “normal purchase, normal sale,” nor does it include expected future production from our generating assets.  Please read “VaR” in our Form

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10-K for a complete description of our valuation methodology.  The daily VaR at March 31, 2017 compared to December 31, 2016 was lower due to a decrease in volatility and price.
Daily and Average VaR for Risk Management Portfolios
(amounts in millions)
 
March 31, 2017
 
December 31, 2016
One day VaR—95 percent confidence level
 
$
15

 
$
38

One day VaR—99 percent confidence level
 
$
21

 
$
53

Average VaR—95 percent confidence level for the rolling twelve months ended
 
$
18

 
$
14

Credit Risk.  The following table represents our credit exposure at March 31, 2017 associated with the mark-to-market portion of our risk management portfolio, on a net basis. We had no exposure related to non-investment grade quality counterparties.
Credit Exposure Summary
(amounts in millions)
 
Investment
Grade Quality
Type of Business:
 
 

Financial institutions
 
$
79

Utility and power generators
 
20

Commercial/industrial/end users
 
3

Total
 
$
102

Interest Rate Risk
We are exposed to fluctuating interest rates related to our variable rate financial obligations, which consist of amounts outstanding under our Credit Agreement. We currently use interest rate swaps to mitigate this interest rate exposure.  Our interest rate hedging instruments are recorded at their fair value.  An increase in LIBOR by 25 basis points would result in a $3.7 million increase in our annual interest expense on the unhedged portion of our indebtedness.
The absolute notional amounts associated with our interest rate contracts were as follows at March 31, 2017 and December 31, 2016, respectively:
 
 
March 31, 2017
 
December 31, 2016
Interest rate swaps (in millions of U.S. dollars)
 
$
767

 
$
769

Fixed interest rate paid (percent)
 
3.03
%
 
3.19
%
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 March 31, 2017
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 March 31, 2017.

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PART II. OTHER INFORMATION
Item 1—LEGAL PROCEEDINGS 
Please read Note 13—Commitments and Contingencies—Legal Proceedings 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 4—MINE SAFETY DISCLOSURES
The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this quarterly report on Form 10-Q.

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Item 6—EXHIBITS  
The following documents are included as exhibits to this Form 10-Q:
Exhibit
Number
 
Description
 
 
 
*2.1

 
Membership Interest Purchase Agreement, dated as of February 23, 2017, by and between Dynegy Inc. and Spruce Generation, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-k of Dynegy Inc. filed on February 28, 2017 File No. 001-33443).
*2.2

 
Asset Purchase Agreement, dated as of February 23, 2017, by and between AEP Generation Resources Inc. and Dynegy Zimmer, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-k of Dynegy Inc. filed on February 28, 2017 File No. 001-33443).
*2.3

 
Asset Purchase Agreement, dated February 23, 2017, by and between Dynegy Conesville, LLC and AEP Generation Resources Inc. (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-k of Dynegy Inc. filed on February 28, 2017 File No. 001-33443).
*2.4

 
Asset Purchase Agreement dated April 21, 2017, by and among Dynegy Zimmer, LLC, Dynegy Miami Fort, LLC, AES Ohio Generation, LLC and The Dayton Power and Light Company (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-k of Dynegy Inc. filed on April 24, 2017 File No. 001-33443).
3.1

 
Dynegy Inc. Seventh Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-k of Dynegy Inc. filed on March 3, 2017 File No. 001-33443).
**10.1

 
Form of Performance Award Agreement (CEO) (2017 Awards).
**10.2

 
Form of Performance Award Agreement (EVP) (2017 Awards).
**10.3

 
Form of Stock Unit Award Agreement (CEO) (2017 Awards).
**10.4

 
Form of Stock Unit Award Agreement (Executive Management) (2017 Awards).
**10.5

 
Form of Non-Qualified Stock Option Award Agreement (CEO) (2017 Awards).
**10.6

 
Form of Non-Qualified Stock Option Award Agreement (2017 Awards).
**10.7

 
Amendment and Waiver Agreement, dated February 2, 2017, to the Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and MUFG Union Bank, N.A.
**10.8

 
Amendment Agreement, dated March 8, 2017, to the Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and MUFG Union Bank, N.A.
**10.9

 
Second Amendment Agreement, dated April 21, 2017, to the Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and MUFG Union Bank, N.A.
**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.
**95.1

 
Mine Safety Violations and Other Legal Matter Disclosures pursuant to section 1503 of the Dodd-Frank Act.
**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 Linkbase Document
**101.LAB

 
XBRL Taxonomy Extension Label Linkbase Document
**101.PRE

 
XBRL Taxonomy Extension Presentation Linkbase Document
__________________________________________
**
Filed herewith.
*
Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Dynegy will furnish the omitted schedules and exhibits to the Securities and Exchange Commission upon request by the Commission.
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,

71


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.

72


DYNEGY INC.
 
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.
 
 
 
 
DYNEGY INC.
 
 
 
 
Date:
May 5, 2017
By:
/s/ CLINT C. FREELAND
 
 
 
Clint C. Freeland
Executive Vice President and Chief Financial Officer


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